As filed with the Securities and Exchange
Commission on June 23, 2011
Registration
No. 333-
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
MEMORIAL PRODUCTION PARTNERS
LP
(Exact name of registrant as
specified in its charter)
|
|
|
|
|
Delaware
(State or other jurisdiction
of
incorporation or organization)
|
|
1311
(Primary Standard
Industrial
Classification Code Number)
|
|
90-0726667
(IRS Employer
Identification Number)
|
1401 McKinney, Suite 1025
Houston, Texas 77010
(713) 579-5700
(Address, including zip
code, and telephone number, including area code, of
registrants principal executive offices)
John A. Weinzierl
President, Chief Executive Officer and Chairman
Memorial Production Partners GP LLC
1401 McKinney, Suite 1025
Houston, Texas 77010
(713) 579-5700
(Name, address, including
zip code, and telephone number, including area code, of agent
for service)
Copies to:
|
|
|
John Goodgame
Akin Gump Strauss Hauer & Feld LLP
1111 Louisiana Street, 44th Floor
Houston, Texas 77002
(713) 220-8144
|
|
Douglas E. McWilliams
Jeffery K. Malonson
Vinson & Elkins L.L.P.
1001 Fannin, Suite 2500
Houston, Texas 77002
(713) 758-2222
|
Approximate date of commencement of proposed sale to the
public: As soon as practicable after this
Registration Statement becomes effective.
If any of the securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to
Rule 415 under the Securities Act of 1933, check the
following
box. o
If this Form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act,
check the following box and list the Securities Act registration
statement number of the earlier effective registration statement
for the same
offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(c) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
If this Form is a post-effective amendment filed pursuant to
Rule 462(d) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
|
|
|
|
Large
accelerated
filer o
|
Accelerated
filer o
|
Non-accelerated
filer þ
|
Smaller
reporting
company o
|
(Do not check if a smaller reporting company)
CALCULATION
OF REGISTRATION FEE
|
|
|
|
|
|
|
|
|
|
Proposed Maximum
|
|
|
Amount of
|
Title of Each Class of
|
|
|
Aggregate
|
|
|
Registration
|
Securities to be Registered
|
|
|
Offering Price(1)(2)
|
|
|
Fee
|
Common units representing limited partner interests
|
|
|
$287,500,000
|
|
|
$33,379
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes common units issuable upon exercise of the
underwriters option to purchase additional common units. |
|
(2) |
|
Estimated solely for the purpose of calculating the registration
fee pursuant to Rule 457(o). |
The Registrant hereby amends this Registration Statement on
such date or dates as may be necessary to delay its effective
date until the Registrant shall file a further amendment which
specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act of 1933 or until the Registration
Statement shall become effective on such date as the Securities
and Exchange Commission, acting pursuant to said
Section 8(a), may determine.
The
information in this preliminary prospectus is not complete and
may be changed. These securities may not be sold until the
registration statement filed with the Securities and Exchange
Commission is effective. This preliminary prospectus is not an
offer to sell nor does it seek an offer to buy these securities
in any jurisdiction where the offer or sale is not permitted.
|
SUBJECT TO COMPLETION DATED
JUNE 23, 2011
PRELIMINARY PROSPECTUS
Memorial Production Partners
LP
Common Units
Representing Limited Partner
Interests
We are a Delaware limited partnership formed in April 2011 by
Memorial Resource Development LLC to own and acquire oil and
natural gas properties in North America. This is the initial
public offering of our common units. No public market currently
exists for our common units. We currently estimate that the
initial public offering price per common unit will be between
$ and
$ per common unit. We intend to
apply to list our common units on the NASDAQ Global Market under
the symbol MEMP.
Investing in our common units involves risks. Please read
Risk Factors beginning on page 22.
These risks include the following:
|
|
|
|
|
We may not have sufficient cash flow from operations to pay the
minimum quarterly distribution on our common units following the
establishment of cash reserves and payment of fees and expenses,
including payments to our general partner.
|
|
|
|
Our estimated oil and natural gas reserves will naturally
decline over time, and we may be unable to sustain distributions
at the level of our minimum quarterly distribution.
|
|
|
|
Oil and natural gas prices are very volatile and a decline in
oil or natural gas prices could cause us to reduce our
distributions or cease paying distributions altogether.
|
|
|
|
Our general partner and its affiliates own a controlling
interest in us and will have conflicts of interest with, and owe
limited fiduciary duties to, us.
|
|
|
|
Memorial Resource, the Funds and other affiliates of our general
partner will not be limited in their ability to compete
with us.
|
|
|
|
Neither we nor our general partner have any employees and we
will rely solely on the employees of Memorial Resource to manage
our business. The management team of Memorial Resource, which
includes the individuals who will manage us, will also perform
substantially similar services for itself and will own and
operate its own assets, and thus will not be solely focused on
our business.
|
|
|
|
Our unitholders have limited voting rights and are not entitled
to elect our general partner or its board of directors.
|
|
|
|
Our unitholders will experience immediate and substantial
dilution of $ per unit.
|
|
|
|
Our tax treatment depends on our status as a partnership for
federal income tax purposes.
|
|
|
|
Our unitholders will be required to pay taxes on their share of
our income even if they do not receive any cash distributions
from us.
|
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or determined if this prospectus is truthful or
complete. Any representation to the contrary is a criminal
offense.
|
|
|
|
|
|
|
|
|
|
|
Per Common Unit
|
|
Total
|
|
Public offering price
|
|
$
|
|
|
|
$
|
|
|
Underwriting discount(1)
|
|
$
|
|
|
|
$
|
|
|
Proceeds, before expenses, to Memorial Production Partners LP
|
|
$
|
|
|
|
$
|
|
|
|
|
|
(1) |
|
Excludes a structuring fee equal
to % of the gross proceeds of this
offering payable to Citigroup Global Markets Inc. |
To the extent that the underwriters sell more
than
common units in this offering, the underwriters have the option
to purchase up to an
additional
common units on the same terms and conditions as set forth above.
The underwriters expect to deliver the common units on or
about ,
2011.
|
|
|
|
|
Citi
|
|
Raymond James
|
|
Wells Fargo Securities
|
J.P. Morgan
,
2011
TABLE OF
CONTENTS
|
|
|
|
|
|
|
Page
|
|
|
|
|
1
|
|
|
|
|
1
|
|
|
|
|
2
|
|
|
|
|
2
|
|
|
|
|
3
|
|
|
|
|
3
|
|
|
|
|
4
|
|
|
|
|
4
|
|
|
|
|
5
|
|
|
|
|
6
|
|
|
|
|
7
|
|
|
|
|
8
|
|
|
|
|
9
|
|
|
|
|
10
|
|
|
|
|
10
|
|
|
|
|
10
|
|
|
|
|
12
|
|
|
|
|
16
|
|
|
|
|
18
|
|
|
|
|
20
|
|
|
|
|
22
|
|
|
|
|
22
|
|
|
|
|
39
|
|
|
|
|
53
|
|
|
|
|
58
|
|
|
|
|
59
|
|
|
|
|
60
|
|
|
|
|
61
|
|
|
|
|
61
|
|
|
|
|
63
|
|
|
|
|
65
|
|
|
|
|
67
|
|
|
|
|
68
|
|
|
|
|
71
|
|
|
|
|
72
|
|
|
|
|
80
|
|
|
|
|
84
|
|
|
|
|
84
|
|
|
|
|
85
|
|
|
|
|
87
|
|
|
|
|
89
|
|
|
|
|
91
|
|
i
|
|
|
|
|
|
|
Page
|
|
|
|
|
91
|
|
|
|
|
91
|
|
|
|
|
92
|
|
|
|
|
92
|
|
|
|
|
94
|
|
|
|
|
95
|
|
|
|
|
96
|
|
|
|
|
98
|
|
|
|
|
100
|
|
|
|
|
100
|
|
|
|
|
107
|
|
|
|
|
108
|
|
|
|
|
108
|
|
|
|
|
111
|
|
|
|
|
112
|
|
|
|
|
119
|
|
|
|
|
122
|
|
|
|
|
124
|
|
|
|
|
126
|
|
|
|
|
127
|
|
|
|
|
128
|
|
|
|
|
128
|
|
|
|
|
129
|
|
|
|
|
129
|
|
|
|
|
129
|
|
|
|
|
130
|
|
|
|
|
130
|
|
|
|
|
132
|
|
|
|
|
134
|
|
|
|
|
135
|
|
|
|
|
138
|
|
|
|
|
143
|
|
|
|
|
144
|
|
|
|
|
146
|
|
|
|
|
150
|
|
|
|
|
151
|
|
|
|
|
152
|
|
|
|
|
152
|
|
|
|
|
153
|
|
|
|
|
153
|
|
|
|
|
155
|
|
|
|
|
156
|
|
|
|
|
156
|
|
|
|
|
157
|
|
ii
|
|
|
|
|
|
|
Page
|
|
|
|
|
159
|
|
|
|
|
159
|
|
|
|
|
161
|
|
|
|
|
162
|
|
|
|
|
164
|
|
|
|
|
164
|
|
|
|
|
165
|
|
|
|
|
165
|
|
|
|
|
166
|
|
|
|
|
168
|
|
|
|
|
168
|
|
|
|
|
175
|
|
|
|
|
178
|
|
|
|
|
178
|
|
|
|
|
178
|
|
|
|
|
178
|
|
|
|
|
180
|
|
|
|
|
180
|
|
|
|
|
180
|
|
|
|
|
180
|
|
|
|
|
180
|
|
|
|
|
181
|
|
|
|
|
182
|
|
|
|
|
182
|
|
|
|
|
183
|
|
|
|
|
184
|
|
|
|
|
186
|
|
|
|
|
186
|
|
|
|
|
187
|
|
|
|
|
187
|
|
|
|
|
188
|
|
|
|
|
189
|
|
|
|
|
189
|
|
|
|
|
189
|
|
|
|
|
189
|
|
|
|
|
189
|
|
|
|
|
190
|
|
|
|
|
190
|
|
|
|
|
190
|
|
|
|
|
191
|
|
|
|
|
191
|
|
|
|
|
191
|
|
|
|
|
192
|
|
iii
You should rely only on the information contained in this
prospectus. We have not, and the underwriters have not,
authorized anyone to provide you with different information. If
anyone provides you with different or inconsistent information,
you should not rely on it. We are not, and the underwriters are
not, making an offer to sell these securities in any
jurisdiction where an offer or sale is not permitted. You should
assume that the information appearing in this prospectus is
accurate as of the date on the front cover of this prospectus
only. Our business, financial condition, results of operations
and prospects may have changed since that date.
Through and
including ,
2011 (25 days after the commencement of this offering), all
dealers that effect transactions in our common units, whether or
not participating in this offering, may be required to deliver a
prospectus. This delivery is in addition to a dealers
obligation to deliver a prospectus when acting as an underwriter
and with respect to their unsold allotments or subscriptions.
This prospectus contains forward-looking statements that are
subject to a number of risks and uncertainties, many of which
are beyond our control. Please read Risk Factors and
Forward-Looking Statements.
iv
Industry
and Market Data
The market data and certain other statistical information used
throughout this prospectus are based on independent industry
publications, government publications or other published
independent sources. Some data is also based on our good faith
estimates. Although we believe these third-party sources are
reliable and that the information is accurate and complete, we
have not independently verified the information.
Commonly
Used Defined Terms
As used in this prospectus, unless we indicate otherwise, the
following terms have the following meanings:
|
|
|
|
|
Memorial Production Partners, the
partnership, we, our,
us or like terms refer collectively to Memorial
Production Partners LP and its subsidiaries;
|
|
|
|
our general partner refers to Memorial Production
Partners GP LLC, our general partner;
|
|
|
|
our predecessor refers collectively to (a) BlueStone
Natural Resources Holdings, LLC, (b) certain oil and natural gas
properties owned by Classic Hydrocarbons Holdings, L.P., and (c)
for periods after April 8, 2011, certain oil and natural
gas properties owned by WHT Energy Partners LLC, a subsidiary of
Memorial Resource that acquired those properties in April 2011,
which are collectively our predecessor for accounting purposes
and the owners, prior to the formation transactions, of the
Partnership Properties;
|
|
|
|
the Funds refers collectively to Natural Gas
Partners VIII, L.P. and Natural Gas Partners IX, L.P.;
|
|
|
|
Memorial Resource refers collectively to Memorial
Resource Development LLC and its subsidiaries;
|
|
|
|
Partnership Properties or our properties
refers to the properties, producing wells, and related oil and
natural gas interests to be contributed to us by our predecessor
and certain other subsidiaries of Memorial Resource in
connection with this offering;
|
|
|
|
formation transactions refers to (i) the
contribution by the Funds of their respective controlling
ownership interests in certain of their subsidiaries (including
our predecessor) to Memorial Resource prior to the closing of
this offering and (ii) the contribution by Memorial
Resource to us of the Partnership Properties at the closing of
this offering, in each case including transactions related
thereto, which are described on page 7; and
|
|
|
|
our management, our employees, or
similar terms refer to the management or other personnel of our
general partner or, as applicable, provided to us or our general
partner by Memorial Resource under an omnibus agreement among
us, our general partner and Memorial Resource.
|
v
SUMMARY
This summary highlights information contained elsewhere in
this prospectus. You should read the entire prospectus
carefully, including Risk Factors beginning on
page 22 and the historical and pro forma financial
statements and the notes to those financial statements. The
information presented in this prospectus assumes that the
underwriters do not exercise their option to purchase additional
common units, unless otherwise indicated.
Unless we indicate otherwise, our financial, reserve and
operating information in this prospectus is presented on a pro
forma basis as if this offering and the other transactions
contemplated by this prospectus, including the formation
transactions, had occurred on January 1, 2010 or
April 1, 2010, as applicable, in the case of pro forma
financial income statement or operating data, and on
December 31, 2010 or March 31, 2011, as applicable, in
the case of pro forma balance sheet information. We include a
glossary of some of the oil and natural gas industry terms used
in this prospectus in Appendix B.
The pro forma estimated proved reserve information for all of
the Partnership Properties as of December 31, 2010
contained in this prospectus is based on the following:
(1) approximately 53% of the estimated proved reserve
volumes are based on a reserve report relating to our South
Texas properties prepared by the independent petroleum engineers
of Netherland, Sewell & Associates, Inc. (or NSAI), a
summary of which is included in this prospectus as
Appendix C; (2) approximately 35% of the estimated
proved reserve volumes are based on evaluations relating to
certain of our East Texas properties prepared by Memorial
Resources internal reserve engineers and audited by NSAI,
a summary of which is included in this prospectus as
Appendix D; and (3) the remaining approximately 12% of
the estimated proved reserve volumes are based on a reserve
report relating to certain of our East Texas properties prepared
by the independent petroleum engineers of Miller and Lents, Ltd.
(or Miller and Lents), a summary of which is included in this
prospectus as Appendix E. We refer to these reports and
evaluations collectively as our reserve reports.
Memorial
Production Partners LP
Overview
We are a Delaware limited partnership formed in April 2011 by
Memorial Resource to own and acquire oil and natural gas
properties in North America. Our primary business objective is
to generate stable cash flows, allowing us to make quarterly
cash distributions to our unitholders and, over time, to
increase those quarterly cash distributions. We believe our
properties are well suited for our partnership because they
consist of mature onshore oil and natural gas reservoirs with
long-lived, predictable production profiles and modest capital
requirements. As of December 31, 2010, our total estimated
proved reserves were approximately 325 Bcfe, of which
approximately 81% were classified as proved developed reserves.
Based on our pro forma average net production for the year ended
December 31, 2010 of 52 MMcfe/d, our total estimated
proved reserves had a
reserve-to-production
ratio of 17 years. Based on proved reserves volumes at
December 31, 2010, we or Memorial Resource operate 94% of
the properties in which we have interests, and we own an average
working interest of 41% across our oil and natural gas
properties.
We believe our business relationship with Memorial Resource,
which owns our general partner and will own
approximately % of our outstanding
common units and all of our subordinated units, will enhance our
ability to maintain or grow our production and expand our proved
reserves base over time. Memorial Resource is a Delaware limited
liability company formed by Natural Gas Partners VIII, L.P. and
Natural Gas Partners IX, L.P., which we refer to as the Funds,
to own, acquire, exploit and develop oil and natural gas
properties and to own our general partner. As part of the
formation transactions, the Funds will contribute to Memorial
Resource their respective ownership of five separate portfolio
companies (including our predecessor), all of which are engaged
in the business of owning, acquiring, exploiting, and developing
oil and natural gas properties, and certain of which will
contribute the Partnership Properties to us. Memorial Resource
will engage in its business with the objective of growing its
reserves, production and cash flows, as well as owning our
general partner and a significant limited partner interest
in us.
1
Our
Properties
Our properties are located in South and East Texas and consist
of mature, legacy onshore oil and natural gas reservoirs. We
believe our properties are well suited for our partnership
because they have predictable production profiles, low decline
rates, long reserve lives and modest capital requirements. The
Partnership Properties consist of operated working interests in
producing and undeveloped leasehold acreage and in identified
producing wells in South and East Texas, and non-operated
working interests in producing and undeveloped leasehold
acreage. As of December 31, 2010, we owned
133,309 gross (112,828 net) acres of developed properties
and 11,876 gross (4,501 net) acres of undeveloped
properties, all held by production, with 345 proved low-risk
infill drilling, recompletion and development opportunities in
our core operational areas. As of December 31, 2010, we had
interests in 1,290 gross (609 net) producing wells across
our properties, with an average working interest of 47%. Based
on our reserve reports, the average estimated decline rate for
our existing proved developed producing reserves is
approximately 9% for 2011, approximately 9% compounded average
decline for the subsequent four years and approximately 8%
thereafter. As of December 31, 2010, approximately
60 Bcfe, or 19%, of our estimated proved reserves were
classified as proved undeveloped, of which approximately 83%
were natural gas. Based on the production estimates and pricing
assumptions included in our reserve reports, we believe that
through 2015, our low-risk development inventory will provide us
with the opportunity to maintain our targeted average net
production of 49 MMcfe/d without acquiring incremental
reserves.
The following table summarizes pro forma information by
producing region regarding our estimated oil and natural gas
reserves as of December 31, 2010 and our average net
production for the year ended December 31, 2010. The
reserve estimates attributable to the Partnership Properties are
derived from our reserve reports.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Pro Forma
|
|
|
Average Net Pro
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Net Proved Reserves
|
|
|
Forma Production
|
|
|
Reserve-to-
|
|
|
Producing
|
|
|
|
|
|
|
% Natural
|
|
|
% Proved
|
|
|
|
|
|
|
|
|
Production
|
|
|
Wells
|
|
|
|
Bcfe
|
|
|
Gas
|
|
|
Developed
|
|
|
MMcfe/d
|
|
|
%
|
|
|
Ratio(1)
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Years)
|
|
|
|
|
|
|
|
|
South Texas
|
|
|
172.2
|
|
|
|
98
|
%
|
|
|
87
|
%
|
|
|
32
|
|
|
|
61
|
%
|
|
|
15
|
|
|
|
563
|
|
|
|
424
|
|
East Texas
|
|
|
152.5
|
|
|
|
76
|
%
|
|
|
76
|
%
|
|
|
20
|
|
|
|
39
|
%
|
|
|
21
|
|
|
|
727
|
|
|
|
185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
324.7
|
|
|
|
88
|
%
|
|
|
81
|
%
|
|
|
52
|
|
|
|
100
|
%
|
|
|
17
|
|
|
|
1,290
|
|
|
|
609
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The average
reserve-to-production
ratio is calculated by dividing estimated pro forma net proved
reserves as of December 31, 2010 by average pro forma net
production for the year ended December 31, 2010. |
Our
Hedging Strategy
We expect to adopt a hedging policy designed to reduce the
impact to our cash flows from commodity price volatility. Under
this policy, we intend to enter into commodity derivative
contracts covering approximately 65% to 85% of our estimated
production from total proved developed producing reserves over a
three-to-five
year period at any given point of time. We may, however, from
time to time hedge more or less than this approximate range.
Memorial Resource will contribute to us at the closing of this
offering derivative contracts for the six months ending
December 31, 2011 and the years ending December 31,
2012, 2013, 2014, and 2015 covering approximately 76%, 75%, 69%,
14% and 8%, respectively, of our estimated production from our
total proved developed producing reserves existing as of
December 31, 2010, based on our reserve reports.
Our commodity derivative contracts may consist of natural gas,
oil and NGL financial swaps, put options and/or collar contracts
and natural gas basis financial swaps. By removing a significant
portion of price volatility associated with production, we
believe we will mitigate, but not eliminate, the potential
negative effects of reductions in commodity prices on our cash
flow from operations for those periods. However, our hedging
activity may also reduce our ability to benefit from increases
in commodity prices. Additionally, we intend to individually
identify these non-speculative hedges as designated
hedges for U.S. federal income tax purposes as we
enter into them. For a description of our commodity derivative
contracts, please read
2
Managements Discussion and Analysis of Financial
Condition and Results of Operations Pro Forma
Liquidity and Capital Resources Commodity Derivative
Contracts.
Our
Principal Business Relationships
We view our relationships with Memorial Resource, Natural Gas
Partners and the Funds as significant competitive strengths. We
believe these relationships will provide us with potential
acquisition opportunities from a portfolio of additional oil and
natural gas properties that meet our acquisition criteria, as
well as access to personnel with extensive technical expertise
and industry relationships.
Our
Relationship with Memorial Resource
Following the completion of this offering, Memorial Resource
will be our largest unitholder,
holding
common units (approximately % of
all outstanding)
and
subordinated units (100% of all outstanding), and will own the
voting interests in our general partner and 50% of the economic
interest in our incentive distribution rights. After giving
effect to the formation transactions, Memorial Resource had
(i) total estimated proved reserves of 1,036 Bcfe at
December 31, 2010, primarily located in East Texas, North
Louisiana and the Rockies, of which approximately 81% were
natural gas, and approximately 34% were classified as proved
developed reserves, and (ii) interests in over
398,000 gross (173,000 net) acres of undeveloped
properties. We believe that many of these properties are (or
after additional capital is invested will become) suitable for
us, based on our criteria that suitable properties consist of
mature onshore oil and natural gas reservoirs with long-lived,
low-decline, predictable production profiles. We also believe
the largely contiguous and overlapping nature of Memorial
Resources and our East Texas acreage, along with joint
ownership in specific properties, will provide key operational,
logistical and technical benefits derived from our aligned
interests and information sharing among personnel, in addition
to various economic benefits.
The following table summarizes pro forma information by
producing region regarding Memorial Resources estimated
oil and natural gas reserves as of December 31, 2010 and
its average net production for the year ended December 31,
2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Pro Forma
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Net Proved Reserves(1)
|
|
|
Average Net Pro
|
|
|
Reserve-to-
|
|
|
Producing
|
|
|
|
|
|
|
|
|
|
% Proved
|
|
|
Forma Production
|
|
|
Production
|
|
|
Wells
|
|
|
|
Bcfe
|
|
|
% Natural Gas
|
|
|
Developed
|
|
|
MMcfe/d
|
|
|
%
|
|
|
Ratio(2)
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Years)
|
|
|
|
|
|
|
|
|
East Texas(3)
|
|
|
760.6
|
|
|
|
84%
|
|
|
|
30%
|
|
|
|
43
|
|
|
|
64%
|
|
|
|
48
|
|
|
|
1,067
|
|
|
|
306
|
|
North Louisiana
|
|
|
224.7
|
|
|
|
73%
|
|
|
|
44%
|
|
|
|
18
|
|
|
|
27%
|
|
|
|
35
|
|
|
|
267
|
|
|
|
172
|
|
Rockies
|
|
|
51.0
|
|
|
|
67%
|
|
|
|
41%
|
|
|
|
6
|
|
|
|
9%
|
|
|
|
25
|
|
|
|
123
|
|
|
|
85
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,036.3
|
|
|
|
81%
|
|
|
|
34%
|
|
|
|
67
|
|
|
|
100%
|
|
|
|
43
|
|
|
|
1,457
|
|
|
|
563
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Memorial Resources estimated pro forma net proved reserves
are based primarily on reserve reports prepared by third-party
independent petroleum engineers. |
|
(2) |
|
The average
reserve-to-production
ratio is calculated by dividing estimated pro forma net proved
reserves as of December 31, 2010 by average pro forma net
production for the year ended December 31, 2010. |
|
(3) |
|
Includes 169 Bcfe of reserves associated with properties in
which we have a joint ownership interest. Please read
Our Partnership Structure and Formation
Transactions Background Information Regarding Our
Predecessor and the Partnership Properties. |
As a result of its significant ownership interests in us and our
general partner, we believe Memorial Resource will be motivated
to support the successful execution of our business strategy and
will provide us with opportunities to pursue acquisitions that
will be accretive to our unitholders. Memorial Resource views
our partnership as part of its growth strategy, and we believe
that Memorial Resource will be incentivized to contribute or
sell additional assets to us and to pursue acquisitions jointly
with us in the future. However, Memorial Resource will regularly
evaluate acquisitions and dispositions and may elect to acquire
or dispose of properties in the future without offering us the
opportunity to participate in those transactions. Moreover,
after
3
this offering, Memorial Resource will continue to be free to act
in a manner that is beneficial to its interests without regard
to ours, which may include electing not to present us with
future acquisition opportunities. Although we believe Memorial
Resource will be incentivized to offer properties to us for
purchase, none of Memorial Resource, the Funds or any of their
affiliates will have any obligation to sell or offer properties
to us following the consummation of this offering. If Memorial
Resource fails to present us with, or successfully competes
against us for, acquisition opportunities, then our ability to
replace or increase our estimated proved reserves may be
impaired, which would adversely affect our cash flow from
operations and our ability to make cash distributions to our
unitholders. Please read Conflicts of Interest and
Fiduciary Duties.
Memorial Resource will also provide management, administrative,
and operations personnel to us and our general partner under an
omnibus agreement that it will enter into with us and our
general partner at the completion of this offering. Under this
agreement, we will utilize Memorial Resources staff of 50
engineers and geologists and 54 management and administrative
personnel as of May 31, 2011, who collectively have an
average of 24 years of experience operating properties in
our areas of operations. Please read Management for
more information about the management of our partnership and our
use of Memorial Resource personnel, and Certain
Relationships and Related Party Transactions
Agreements Governing the Transactions Omnibus
Agreement for more information about the omnibus agreement.
Our
Relationship with Natural Gas Partners and the
Funds
Founded in 1988, Natural Gas Partners, or NGP, is a family of
private equity investment funds with aggregate committed capital
of over $7 billion, organized to make direct equity
investments in the energy industry. NGP is part of the
investment platform of NGP Energy Capital Management, one of the
leading investment franchises in the natural resources sector
with over $9 billion in aggregate committed capital under
management. The employees of NGP are experienced energy
professionals with substantial expertise in investing in the oil
and natural gas business. In connection with NGPs
business, these employees review a large number of potential
acquisitions and are involved in decisions relating to the
acquisition and disposition of oil and natural gas assets by the
various portfolio companies in which NGP owns interests. We
believe that our relationship with NGP, and its experience
investing in oil and natural gas companies, provides us with a
number of benefits, including increased exposure to acquisition
opportunities and access to a significant group of transactional
and financial professionals who have experience in assisting the
companies in which it has invested to meet their financial and
strategic growth objectives. Although we may have the
opportunity to make acquisitions as a result of our relationship
with NGP, NGP has no legal obligation to offer to us (or inform
us about) any acquisition opportunities, may decide not to offer
any acquisition opportunities to us and is not restricted from
competing with us, and we cannot say which, if any, of such
potential acquisition opportunities we would choose to pursue.
The Funds, which are two of the private equity funds managed by
NGP, collectively own 100% of Memorial Resource. The Funds also
will collectively directly own, through non-voting membership
interests in our general partner, 50% of the economic interest
in our incentive distribution rights. The remaining economic
interest in our incentive distribution rights is owned by
Memorial Resource. Given this alignment of interests between
NGP, the Funds, Memorial Resource and us, we believe we will
benefit from the collective expertise of NGPs employees
and their extensive network of industry relationships, and
accordingly the access to potential acquisition opportunities
that might not otherwise be available to us.
Our
Business Strategies
Our primary business objective is to generate stable cash flows,
allowing us to make quarterly cash distributions to our
unitholders and, over time, to increase those quarterly cash
distributions. To achieve our objective, we intend to execute
the following business strategies:
|
|
|
|
|
Maintain and grow a stable production profile through accretive
acquisitions and low-risk development;
|
|
|
|
Strategically utilize our relationship with Memorial Resource,
the Funds, and their respective affiliates (including NGP) to
gain access to and, from time to time, acquire producing oil and
natural gas properties that meet our acquisition criteria;
|
4
|
|
|
|
|
Leverage our relationships with Memorial Resource, the Funds,
and their respective affiliates (including NGP) to participate
in acquisitions of third party producing properties and to
increase the size and scope of our potential third-party
acquisition targets;
|
|
|
|
Exploit opportunities on our current properties and manage our
operating costs and capital expenditures;
|
|
|
|
Reduce exposure to commodity price risk and stabilize cash flows
through a disciplined commodity hedging policy; and
|
|
|
|
Maintain reasonable levels of indebtedness to permit us to
opportunistically finance acquisitions.
|
For a more detailed description of our business strategies,
please read Business and Properties Our
Business Strategies.
Our
Competitive Strengths
We believe that the following competitive strengths will allow
us to successfully execute our business strategies and achieve
our objective of generating and growing cash available for
distribution:
|
|
|
|
|
Our long-lived reserves with significant production history and
predictable production decline rates;
|
|
|
|
Our relationships with Memorial Resource, the Funds, and their
respective affiliates (including NGP), which we believe will
provide us with access to a portfolio of additional oil and
natural gas properties that meet our acquisition criteria;
|
|
|
|
Our management teams extensive experience in the
acquisition, development and integration of oil and natural gas
assets;
|
|
|
|
Our relationship with Memorial Resource, which provides us with
extensive technical expertise in and familiarity with developing
and operating oil and natural gas assets within our core focus
areas;
|
|
|
|
Our relationships with Memorial Resource, the Funds, and their
respective affiliates (including NGP), which we believe will
help us with access to and in the evaluation and execution of
future acquisitions;
|
|
|
|
Our diverse distribution of reserve value, with 1,290 gross
(609 net) producing wells as of December 31, 2010, none of
which contains estimated proved reserves in excess of 2% of our
total estimated proved reserves as of December 31, 2010;
|
|
|
|
Our inventory of 345 proved low-risk infill drilling,
recompletion and development opportunities in our core
operational areas; and
|
|
|
|
Our competitive cost of capital and financial flexibility.
|
For a more detailed discussion of our competitive strengths,
please read Business and Properties Our
Competitive Strengths.
5
Risk
Factors
An investment in our common units involves risks. Below is a
summary of certain key risk factors that you should consider in
evaluating an investment in our common units. This list is not
exhaustive. Please read the full discussion of these risks and
other risks described under Risk Factors beginning
on page 22.
Risks
Related to Our Business
|
|
|
|
|
We may not have sufficient cash to pay the minimum quarterly
distribution on our common units, following the establishment of
cash reserves and payment of fees and expenses, including
payments to our general partner and its affiliates.
|
|
|
|
Our estimated oil and natural gas reserves will naturally
decline over time, and it is unlikely that we will be able to
sustain distributions at the level of our minimum quarterly
distribution without making accretive acquisitions or
substantial capital expenditures that maintain our asset base.
|
|
|
|
Oil and natural gas prices are very volatile, and a decline in
oil or natural gas prices will cause a decline in our cash flow
from operations, which could cause us to reduce our
distributions or cease paying distributions altogether.
|
Risks
Inherent in an Investment in Us
|
|
|
|
|
Our general partner and its affiliates own a controlling
interest in us and will have conflicts of interest with, and owe
limited fiduciary duties to, us, which may permit them to favor
their own interests to the detriment of our unitholders.
|
|
|
|
Memorial Resource, the Funds and other affiliates of our general
partner will not be limited in their ability to compete with us,
which could cause conflicts of interest and limit our ability to
acquire additional assets or businesses.
|
|
|
|
Neither we nor our general partner have any employees and we
will rely solely on the employees of Memorial Resource to manage
our business. The management team of Memorial Resource, which
includes the individuals who will manage us, will also perform
substantially similar services for itself and will own and
operate its own assets, and thus will not be solely focused on
our business.
|
|
|
|
Our unitholders have limited voting rights and are not entitled
to elect our general partner or its board of directors. Memorial
Resource, as the owner of our general partner, will have the
power to appoint and remove our general partners directors.
|
|
|
|
Even if our unitholders are dissatisfied, they cannot remove our
general partner without Memorial Resources consent.
|
Tax
Risks to Unitholders
|
|
|
|
|
Our tax treatment depends on our status as a partnership for
federal income tax purposes. If the Internal Revenue Service, or
the IRS, were to treat us as a corporation for federal income
tax purposes, then our cash available for distribution to our
unitholders would be substantially reduced.
|
|
|
|
Our unitholders will be required to pay taxes on their share of
our income even if they do not receive any cash distributions
from us.
|
6
Our
Partnership Structure and Formation Transactions
We are a Delaware limited partnership formed by Memorial
Resource to own and acquire oil and natural gas properties. In
connection with this offering, the following transactions, which
we refer to as the formation transactions, will occur:
Prior to the closing of this offering:
|
|
|
|
|
The Funds will contribute their respective controlling ownership
interests in certain of their subsidiaries (including our
predecessor) to Memorial Resource; and
|
|
|
|
Memorial Resource will issue membership interests to the Funds
reflecting an aggregate 100% membership interest in itself, and
will agree to cause our general partner to issue to the Funds an
aggregate 50% non-voting membership interest in itself to the
Funds that will entitle the Funds to 50% of any cash
distributions or common units received by our general partner in
respect of our incentive distribution rights; and
|
At the closing of this offering:
|
|
|
|
|
Memorial Resource will cause certain of its subsidiaries,
including our predecessor, to contribute to us
(i) specified oil and natural gas properties, which we
refer to collectively as the Partnership Properties,
and (ii) commodity derivative contracts for the six months
ending December 31, 2011 and the years ending
December 31, 2012, 2013, 2014, and 2015 covering
approximately 76%, 75%, 69%, 14% and 8%, respectively, of our
estimated production from our total proved developed producing
reserves existing as of December 31, 2010, based on our
reserve reports;
|
|
|
|
We will issue to Memorial
Resource
common units
and subordinated
units, representing an aggregate %
limited partner interest in us;
|
|
|
|
We will issue to our general
partner
general partner units, representing a 0.1% general partner
interest in us, and all of our incentive distribution rights,
which will entitle our general partner to increasing percentages
of the cash we distribute in excess of
$ per unit per quarter;
|
|
|
|
Our general partner will issue an aggregate 50% non-voting
membership interest in itself to the Funds that will entitle the
Funds to 50% of any cash distributions or common units received
by our general partner in respect of our incentive distribution
rights;
|
|
|
|
We expect to receive net proceeds of approximately
$ million from the issuance
and sale
of
common units to the public (based on the midpoint of the price
range set forth on the cover page of this prospectus),
representing a % limited partner
interest in us, and we will use the net proceeds as described in
Use of Proceeds;
|
|
|
|
We expect to borrow approximately $130.0 million under a
new $ million revolving
credit facility, and we will use the proceeds as described in
Use of Proceeds (if the net proceeds from this
offering increase or decrease, then our borrowing under our new
revolving credit facility would correspondingly decrease or
increase, respectively); and
|
|
|
|
We and our general partner will enter into an omnibus agreement
with Memorial Resource, pursuant to which, among other things,
Memorial Resource will provide us and our general partner with
management, administrative and operating services.
|
If the underwriters exercise their option to purchase additional
common units, we will use the net proceeds to reduce
indebtedness incurred under our new revolving credit facility.
If the underwriters exercise in full their option to purchase
additional common units, the ownership interest of the public
unitholders will increase
to
common units, representing an
aggregate % limited partner
interest in us, the ownership interest of our general partner
will increase
to
general partner units, representing a 0.1% general partner
interest in us, and the ownership interest of Memorial Resource
will remain
at
common units and subordinated units, representing an
aggregate % limited partner
interest in us.
7
Background
Information Regarding Our Predecessor and the Partnership
Properties
The Partnership Properties consist of properties that will be
contributed to us by our predecessor (which consists of the
combined financial data of (a) BlueStone Natural Resources
Holdings, LLC, (b) certain oil and natural gas properties owned
by Classic Hydrocarbons Holdings, L.P., and (c) for periods
after April 8, 2011, certain oil and natural gas properties
owned by WHT Energy Partners LLC (WHT), each subsidiaries of
Memorial Resource). The properties being contributed to us by
our predecessor include (1) properties acquired by our
predecessor from Forest Oil Corporation (Forest Oil) in June
2010 (with respect to which certain financial statements are
included elsewhere in this prospectus), (2) properties acquired
by our predecessor from BP America Production Company (BP) in
May 2011 (with respect to which certain financial statements are
included elsewhere in this prospectus) and (3) a 40% undivided
interest in the properties acquired by WHT in April 2011 (with
respect to which certain financial statements are included
elsewhere in this prospectus).
8
Our
Ownership and Organizational Structure
The table and diagram below illustrates our ownership and
organizational structure based on total units outstanding after
giving effect to this offering and the related formation
transactions and assumes that the underwriters do not exercise
their option to purchase additional common units.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ownership
|
|
|
|
Units
|
|
|
Interest
|
|
|
Common units held by the public
|
|
|
|
|
|
|
|
%
|
Common units held by Memorial Resource
|
|
|
|
|
|
|
|
%
|
Subordinated units held by Memorial Resource
|
|
|
|
|
|
|
|
%
|
General partner units
|
|
|
|
|
|
|
0.1
|
%
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
9
Principal
Executive Offices and Internet Address
Our principal executive offices are located at 1401 McKinney,
Suite 1025, Houston, Texas 77010, and our phone number is
(713) 579-5700.
Our website address is www.memorialpp.com and will be activated
in connection with the closing of this offering. We expect to
make our periodic reports and other information filed with or
furnished to the Securities and Exchange Commission, which we
refer to as the SEC, available free of charge through our
website as soon as reasonably practicable after those reports
and other information are electronically filed with or furnished
to the SEC. Information on our website or any other website is
not incorporated by reference into, and does not constitute a
part of, this prospectus.
Management
of the Partnership
We are managed and operated by the board of directors and
executive officers of Memorial Production Partners GP LLC, our
general partner. Upon the completion of this offering, the board
of directors of our general partner will have five members. At
least one of our independent directors will be appointed prior
to the date our common units are listed for trading on the
NASDAQ Global Market, or NASDAQ. Memorial Resource will appoint
our second and third independent directors within 90 days
and one year, respectively, of such date. Memorial Resource owns
100% of the voting membership interests in our general partner
and has the sole right to appoint its entire board of directors.
Unlike shareholders in a publicly traded corporation, our
unitholders will not be entitled to elect our general partner or
the board of directors of our general partner. Some of the
executive officers
and/or
directors of our general partner currently serve as executive
officers
and/or
directors of Memorial Resource, and some of the directors of our
general partner currently serve in executive or other capacities
for the Funds and their affiliates, including NGP. For more
information about the directors and officers of our general
partner, please read Management Directors and
Executive Officers.
Neither we nor our subsidiaries will have any employees. Our
general partner has the sole responsibility for providing the
personnel necessary to conduct our operations, whether through
directly hiring employees or by obtaining the services of
personnel employed by Memorial Resource or others. We will
reimburse our general partner and its affiliates for all
expenses they incur or payments they make on our behalf. Our
partnership agreement provides that our general partner will
determine in good faith the expenses that are allocable to us.
Prior to the closing of this offering, we and our general
partner will enter into an omnibus agreement with Memorial
Resource pursuant to which, among other things, Memorial
Resource will provide management, administrative and operating
services for us and our general partner. Memorial Resource will
not be liable to us for its performance of, or failure to
perform, services under this agreement unless there has been a
final decision determining that Memorial Resource acted in bad
faith or engaged in fraud or willful misconduct or, in the case
of a criminal matter, acted with knowledge that the conduct was
unlawful. Our general partner will determine the expenses
(including general and administrative expenses) to be reimbursed
by us in accordance with our partnership agreement. We currently
expect those general and administrative expenses (including
those to be allocated to us by Memorial Resource) to be
approximately $5.0 million for the twelve months ending
June 30, 2012. Please read Certain Relationships and
Related Party Transactions Agreements Governing the
Transactions Omnibus Agreement.
As is common with publicly traded partnerships and in order to
maintain operational flexibility, we will conduct our operations
through subsidiaries. We will initially have one direct
subsidiary, Memorial Production Operating LLC, a Delaware
limited liability company that will conduct business itself and
through any subsidiaries that it may form or acquire.
Summary
of Conflicts of Interest and Fiduciary Duties
Our general partner has a legal duty to manage us in a manner
beneficial to the holders of our common and subordinated units.
This legal duty originates in statutes and judicial decisions
and is commonly referred to as a fiduciary duty.
However, the officers and directors of our general partner also
have a fiduciary duty to manage the business of our general
partner in a manner beneficial to its owner, which is Memorial
10
Resource. The officers and directors of Memorial Resource, in
turn, have a fiduciary duty to manage Memorial Resources
business in a manner beneficial to its owners, which are the
Funds. Memorial Resource, the Funds, and their respective
affiliates (including NGP) each manage, own, and hold assets and
investments in other entities that compete or may compete with
us. Additionally, certain of our general partners
executive officers and directors will continue to have economic
interests, investments and other economic incentives in
affiliates of the Funds. As a result of these relationships,
conflicts of interest may arise in the future between us and our
unitholders, on the one hand, and our general partner and its
owners and affiliates, on the other hand. For example, our
general partner is entitled to make determinations that affect
our ability to generate the cash flows necessary to make cash
distributions to our unitholders, including determinations
related to:
|
|
|
|
|
purchases and sales of oil and natural gas properties and other
acquisitions and dispositions, including whether to pursue
acquisitions that are also suitable for Memorial Resource, the
Funds or their affiliates;
|
|
|
|
the manner in which our business is operated;
|
|
|
|
the level of our borrowings;
|
|
|
|
the amount, nature and timing of our capital
expenditures; and
|
|
|
|
the amount of cash reserves necessary or appropriate to satisfy
our general and administrative expenses, other expenses and debt
service requirements, and to otherwise provide for the proper
conduct of our business.
|
These determinations will have an effect on the amount of cash
distributions we make to the holders of our units, which in turn
has an effect on whether our general partner receives incentive
cash distributions. For a more detailed description of the
conflicts of interest and fiduciary duties of our general
partner, please read Risk Factors Risks
Inherent in an Investment in Us and Conflicts of
Interest and Fiduciary Duties.
Delaware law provides that Delaware limited partnerships may, in
their partnership agreements, restrict or expand the fiduciary
duties owed by the general partner to the limited partners and
the partnership. Our partnership agreement limits the liability
of our general partner and reduces the fiduciary duties it owes
to holders of our common and subordinated units. Our partnership
agreement also restricts the remedies available to holders of
our common units for actions that might otherwise constitute a
breach of the fiduciary duties that our general partner owes to
our unitholders. By purchasing a common unit, unitholders agree
to be bound by the terms of our partnership agreement and,
pursuant to the terms of our partnership agreement, are treated
as having consented to various actions contemplated in our
partnership agreement and conflicts of interest that might
otherwise be considered a breach of fiduciary or other duties
under Delaware law. Please read Conflicts of Interest and
Fiduciary Duties Fiduciary Duties for a
description of the fiduciary duties imposed on our general
partner by Delaware law, the material modifications of these
duties contained in our partnership agreement and certain legal
rights and remedies available to our unitholders.
Additionally, neither our partnership agreement nor the omnibus
agreement contains any restrictions on the ability of Memorial
Resource, the Funds, or any of their respective affiliates
(including NGP and its affiliates portfolio investments)
to compete with us. None of Memorial Resource, the Funds or any
of their respective affiliates (including NGP) is under any
obligation to offer properties or refer acquisitions or other
opportunities to us.
11
The
Offering
|
|
|
Common units offered hereby |
|
common
units or common units if the
underwriters exercise in full their option to purchase
additional common units. |
|
Units outstanding after this offering |
|
common
units
and subordinated
units, representing %
and %, respectively, limited
partner interests in us
(
common units and subordinated units,
representing %
and %, respectively, limited
partner interests in us if the underwriters exercise in full
their option to purchase additional common units). The general
partner will own general partner units,
or
general partner units if the underwriters exercise their option
to purchase additional common units in full, in each case
representing a 0.1% general partner interest in us. |
|
Use of proceeds |
|
We intend to use the estimated net proceeds of approximately
$ million from this offering,
based upon the assumed initial public offering price of
$ per common unit (the midpoint of
the price range set forth on the cover of this prospectus),
after deducting underwriting discounts, structuring fees and
expenses, together with borrowings of approximately
$130.0 million under our new revolving credit facility, to
purchase the Partnership Properties from Memorial Resource and
to pay fees and expenses associated with this offering and our
formation transactions. We will use any net proceeds from the
exercise of the underwriters option to purchase additional
common units to repay additional indebtedness under our new
revolving credit facility. Please read Use of
Proceeds. |
|
Cash distributions |
|
We expect to make a minimum quarterly distribution of
$ per unit per quarter on all
common, subordinated and general partner units
($ per unit on an annualized
basis) to the extent we have sufficient cash from operations
after establishment of cash reserves and payment of fees and
expenses, including payments to our general partner and its
affiliates. We refer to this cash as available cash,
and it is defined in our partnership agreement included in this
prospectus as Appendix A. Our ability to pay the minimum
quarterly distribution is subject to various restrictions and
other factors described in more detail under the caption
Our Cash Distribution Policy and Restrictions on
Distributions. For the first quarter that we are publicly
traded, we will pay our unitholders a prorated distribution
covering the period from the completion of this offering
through ,
2011, based on the actual length of that period. |
|
|
|
Assuming our general partner maintains its 0.1% general partner
interest in us, our partnership agreement requires us to
distribute all of our available cash each quarter in the
following manner during the subordinated period: |
|
|
|
first, 99.9% to the holders of common units
and 0.1% to our general partner, until each common unit has
received the minimum quarterly distribution of
$ plus any arrearages from prior
quarters;
|
12
|
|
|
|
|
second, 99.9% to the holders of subordinated
units and 0.1% to our general partner, until each subordinated
unit has received the minimum quarterly distribution of
$ ; and
|
|
|
|
third, 99.9% to all unitholders, pro rata,
and 0.1% to our general partner, until each unit has received a
distribution of $ .
|
|
|
|
If cash distributions to our unitholders exceed
$ per common and subordinated unit
in any quarter, our general partner will receive, in addition to
distributions on its general partner interest, increasing
percentages, up to 24.9%, of the cash we distribute in excess of
that amount. We refer to these distributions as incentive
distributions. Please read Provisions of Our
Partnership Agreement Relating to Cash Distributions. |
|
|
|
At the closing of this offering, the Funds will hold non-voting
membership interests in our general partner that will entitle
them to collectively receive 50% of any cash distributions made
or common units issued to our general partner in respect of our
incentive distribution rights. All other interests in our
general partner will be owned by Memorial Resource. Please read
Certain Relationships and Related Party
Transactions Amended and Restated Limited Liability
Company Agreement of Memorial Production Partners GP LLC. |
|
|
|
Our ability to pay the minimum quarterly distribution is subject
to various restrictions and other factors described in more
detail in Our Cash Distribution Policy and Restrictions on
Distributions. |
|
|
|
Pro forma cash available for distribution generated during the
year ended December 31, 2010 was approximately
$46.4 million, which would have been sufficient to allow us
to pay the full minimum quarterly distribution on our common
units, general partner units and subordinated units during that
period (assuming the underwriters exercise in full their option
to purchase additional common units). |
|
|
|
Pro forma cash available for distribution during the twelve
months ended March 31, 2011 was approximately
$40.6 million, which would have been sufficient to allow us
to pay the full minimum quarterly distribution on our common
units and general partner units, and a quarterly distribution of
$ on our subordinated units, during
that period (assuming the underwriters exercise in full their
option to purchase additional common units). |
|
|
|
The amount of available cash we need to pay the minimum
quarterly distribution for four quarters on our common units,
general partner units and subordinated units to be outstanding
immediately after this offering is approximately
$ million (or an average of
approximately $ million per
quarter). Please read Our Cash Distribution Policy and
Restrictions on Distributions. |
|
|
|
We believe, based on our financial forecast and related
assumptions included in Our Cash Distribution Policy and
Restrictions on Distributions Estimated Adjusted
EBITDA for the Twelve Months Ending June 30, 2012,
that we will have sufficient available cash to |
13
|
|
|
|
|
pay the aggregate minimum quarterly distribution of
$ million on all of our
common units, general partner units and subordinated units for
the twelve months ending June 30, 2012. However, we do not
have a legal obligation to pay distributions at our minimum
quarterly distribution rate or at any other rate except as
provided in our partnership agreement, and there is no guarantee
that we will make quarterly cash distributions to our
unitholders. Please read Our Cash Distribution Policy and
Restrictions on Distributions. |
|
Subordinated units |
|
Memorial Resource will initially own all of our subordinated
units. The principal difference between our common units and
subordinated units is that, in any quarter during the
subordination period, the subordinated units are entitled to
receive the minimum quarterly distribution only after the common
units have received their minimum quarterly distribution plus
any arrearages in the payment of the minimum quarterly
distribution from prior quarters. Accordingly, holders of
subordinated units may receive a smaller distribution than
holders of common units or no distribution at all. Subordinated
units will not accrue arrearages. |
|
|
|
The subordination period will begin on the closing date of this
offering and will extend until the first business day of any
quarter
after ,
2014 that we have earned and paid from operating surplus, in the
aggregate, distributions on each outstanding common unit,
subordinated unit, and general partner unit equaling or
exceeding the minimum quarterly distribution payable for a
period of twelve consecutive quarters immediately preceding such
date. |
|
|
|
The subordination period will also end if our general partner is
removed other than for cause, provided that no subordinated or
common units held by the holders of the subordinated units or
their affiliates are voted in favor of such removal. |
|
|
|
When the subordination period ends, all subordinated units will
convert into common units on a
one-for-one
basis and all common units thereafter will no longer be entitled
to arrearages. |
|
Early conversion of subordinated units |
|
If we have earned and paid from operating surplus at least
$ (125% of the minimum quarterly
distribution) on each outstanding common unit, subordinated unit
and general partner unit, and the related distribution on the
incentive distribution rights, for each quarter in any
four-quarter period ending on or
after ,
2012, all of the outstanding subordinated units will convert
into common units at the end of such period. |
|
Issuance of additional units |
|
We can issue an unlimited number of additional units, including
units that are senior to the common units in right of
distributions, liquidation and voting, on terms and conditions
determined by our general partner, without the approval of our
unitholders. Please read Units Eligible for Future
Sale and The Partnership Agreement
Issuance of Additional Securities. |
|
Limited voting rights |
|
Our general partner will manage us and operate our business.
Unlike stockholders of a corporation, our unitholders will have
only limited voting rights on matters affecting our business.
Our |
14
|
|
|
|
|
unitholders will have no right to elect our general partner or
its directors on an annual or other continuing basis. Our
general partner may not be removed except by a vote of the
holders of at least
662/3%
of the outstanding common and subordinated units, including any
units owned by our general partner and its affiliates, voting
together as a single class. Upon consummation of this offering,
Memorial Resource and its affiliates will own an aggregate of
approximately % of our outstanding
common and subordinated units (or %
of our outstanding common and subordinated units if the
underwriters exercise their option to purchase additional common
units in full) and will therefore be able to prevent the removal
of our general partner. Please read The Partnership
Agreement Limited Voting Rights. |
|
Limited call right |
|
If at any time our general partner and its affiliates own more
than 80% of the outstanding common units, our general partner
has the right, but not the obligation, to purchase all of the
remaining common units at a purchase price not less than the
then-current market price of the common units, as calculated
pursuant to the terms of our partnership agreement. Upon the
consummation of this offering, Memorial Resource will own
approximately % of our outstanding
common units (or % of our
outstanding common units if the underwriters exercise their
option to purchase additional common units in full) and 100% of
our subordinated units. Please read The Partnership
Agreement Limited Call Right. |
|
Estimated ratio of taxable income to distributions |
|
We estimate that if our unitholders own the common units
purchased in this offering through the record date for
distributions for the period
ending ,
such unitholders will be allocated, on a cumulative basis, an
amount of federal taxable income for that period that will be
less than % of the cash distributed
to such unitholders with respect to that period. Please read
Material Tax Consequences Tax Consequences of
Unit Ownership Ratio of Taxable Income to
Distributions for information regarding the bases for this
estimate. |
|
Material tax consequences |
|
For a discussion of other material federal income tax
consequences that may be relevant to prospective unitholders who
are individual citizens or residents of the United States,
please read Material Tax Consequences. |
|
Agreement to be bound by the partnership agreement |
|
By purchasing a common unit, you will be admitted as a
unitholder of our partnership and will be deemed to have agreed
to be bound by all of the terms of our partnership agreement. |
|
Listing and trading symbol |
|
We intend to apply to list our common units on the NASDAQ Global
Market under the symbol MEMP. |
15
Summary
Historical and Pro Forma Financial Data
We were formed in April 2011 and do not have historical
financial operating results. The following table shows summary
historical financial data of our predecessor, which consists of
the combined financial data of BlueStone Natural Resources
Holdings, LLC, certain oil and natural gas properties owned by
Classic Hydrocarbons Holdings, L.P. and for periods after
April 8, 2011, certain oil and natural gas properties of
WHT Energy Partners LLC, and unaudited pro forma combined
financial data of Memorial Production Partners LP, for the
periods and as of the dates presented. Due to the factors
described in Managements Discussion and Analysis of
Financial Condition and Results of Operations
Overview and Managements Discussion and
Analysis of Financial Condition and Results of
Operations Historical and Pro Forma Financial and
Operating Data Pro Forma Results of
Operations Factors Affecting the Comparability of
the Pro Forma Results of Our Partnership to the Historical
Financial Results of Our Predecessor, our future results
of operations will not be comparable to the historical results
of our predecessor.
The summary historical combined financial data as of
December 31, 2009 and 2010 and for the years ended
December 31, 2008, 2009 and 2010 are derived from the
audited historical combined financial statements of our
predecessor included elsewhere in this prospectus. The summary
historical combined financial data as of March 31, 2010 and
2011 and for the three months ended March 31, 2010 and 2011
are derived from the unaudited historical combined financial
statements of our predecessor included elsewhere in this
prospectus.
The summary unaudited pro forma financial data as of
March 31, 2011 and for the three months ended
March 31, 2011 and the year ended December 31, 2010
are derived from the unaudited pro forma combined financial
statements of Memorial Production Partners LP included elsewhere
in this prospectus. The pro forma adjustments have been prepared
as if certain transactions, which have been completed or which
will be effected prior to or in connection with the closing of
this offering, had taken place on March 31, 2011, in the
case of the unaudited pro forma balance sheet, or as of
January 1, 2010, in the case of the unaudited pro forma
statements of operations. These transactions include:
|
|
|
|
|
adjustments to reflect the acquisitions of oil and natural gas
properties consummated in June 2010, April 2011, and May 2011 by
our predecessor;
|
|
|
|
the contribution by Memorial Resource and certain of its
subsidiaries, including our predecessor, to us of the
Partnership Properties in exchange
for
common units, subordinated units
and $ million in cash and the
issuance to our general partner
of
general partner units, representing a 0.1% general partner
interest in us, and all of our incentive distribution rights;
|
|
|
|
the issuance and sale by us to the public
of
common units in this offering and the application of the net
proceeds as described in Use of Proceeds; and
|
|
|
|
our borrowing of approximately $130.0 million under our new
$ million revolving credit
facility and the application of the net proceeds as described in
Use of Proceeds. If the net proceeds from this
offering increase or decrease, then our borrowing under our new
revolving credit facility would correspondingly decrease or
increase, respectively.
|
You should read the following table in conjunction with
Our Partnership Structure and Formation
Transactions, Use of Proceeds,
Managements Discussion and Analysis of Financial
Condition and Results of Operations, and the historical
combined financial statements of our predecessor and the
unaudited pro forma combined financial statements of Memorial
Production Partners LP included elsewhere in this prospectus.
Among other things, those historical and unaudited pro forma
combined financial statements include more detailed information
regarding the basis of presentation for the following
information.
16
The following table presents Adjusted EBITDA, which we use in
evaluating the liquidity of our business. This financial measure
is not calculated or presented in accordance with generally
accepted accounting principles, or GAAP. We explain this measure
below and reconcile it to net cash from operating activities,
its most directly comparable financial measure calculated and
presented in accordance with GAAP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Memorial Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners LP
|
|
|
|
Our Predecessor
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
|
|
|
|
|
|
|
|
|
|
|
|
|
Months
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Year Ended
|
|
|
Ended
|
|
|
|
Year Ended December 31,
|
|
|
March 31,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
$
|
49,313
|
|
|
$
|
24,541
|
|
|
$
|
37,308
|
|
|
$
|
7,879
|
|
|
$
|
11,641
|
|
|
$
|
87,762
|
|
|
$
|
20,648
|
|
Other income
|
|
|
622
|
|
|
|
319
|
|
|
|
1,433
|
|
|
|
67
|
|
|
|
103
|
|
|
|
1,404
|
|
|
|
99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
49,935
|
|
|
|
24,860
|
|
|
|
38,741
|
|
|
|
7,946
|
|
|
|
11,744
|
|
|
|
89,166
|
|
|
|
20,747
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
8,843
|
|
|
|
11,207
|
|
|
|
13,974
|
|
|
|
2,220
|
|
|
|
5,170
|
|
|
|
23,052
|
|
|
|
6,685
|
|
Exploration
|
|
|
374
|
|
|
|
2,690
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
Production and ad valorem taxes
|
|
|
3,127
|
|
|
|
1,464
|
|
|
|
2,112
|
|
|
|
509
|
|
|
|
693
|
|
|
|
7,387
|
|
|
|
1,703
|
|
Depreciation, depletion and amortization
|
|
|
12,353
|
|
|
|
15,226
|
|
|
|
20,066
|
|
|
|
4,352
|
|
|
|
4,450
|
|
|
|
34,772
|
|
|
|
7,026
|
|
Impairment of proved oil and natural gas properties
|
|
|
14,166
|
|
|
|
3,480
|
|
|
|
11,800
|
|
|
|
1,691
|
|
|
|
|
|
|
|
9,509
|
|
|
|
|
|
General and administrative
|
|
|
3,835
|
|
|
|
4,811
|
|
|
|
6,116
|
|
|
|
1,108
|
|
|
|
1,474
|
|
|
|
5,819
|
|
|
|
1,399
|
|
Accretion
|
|
|
224
|
|
|
|
320
|
|
|
|
663
|
|
|
|
64
|
|
|
|
210
|
|
|
|
1,072
|
|
|
|
276
|
|
(Gain) loss on derivative instruments
|
|
|
(9,815
|
)
|
|
|
(10,834
|
)
|
|
|
(10,264
|
)
|
|
|
(6,636
|
)
|
|
|
703
|
|
|
|
(10,264
|
)
|
|
|
703
|
|
Gain on sale of properties
|
|
|
(7,395
|
)
|
|
|
(7,851
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
|
|
|
|
304
|
|
|
|
890
|
|
|
|
|
|
|
|
|
|
|
|
890
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
25,712
|
|
|
|
20,817
|
|
|
|
45,395
|
|
|
|
3,308
|
|
|
|
12,692
|
|
|
|
72,273
|
|
|
|
17,792
|
|
Operating income (loss)
|
|
|
24,223
|
|
|
|
4,043
|
|
|
|
(6,654
|
)
|
|
|
4,638
|
|
|
|
(948
|
)
|
|
|
16,893
|
|
|
|
2,955
|
|
Interest expense
|
|
|
(3,138
|
)
|
|
|
(2,937
|
)
|
|
|
(4,438
|
)
|
|
|
(606
|
)
|
|
|
(1,035
|
)
|
|
|
(4,365
|
)
|
|
|
(1,092
|
)
|
Income (loss) before income taxes
|
|
$
|
21,085
|
|
|
$
|
1,106
|
|
|
$
|
(11,092
|
)
|
|
$
|
4,032
|
|
|
$
|
(1,983
|
)
|
|
$
|
12,528
|
|
|
$
|
1,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
(225
|
)
|
|
|
|
|
|
|
|
|
|
|
(225
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
21,085
|
|
|
$
|
1,106
|
|
|
$
|
(11,317
|
)
|
|
$
|
4,032
|
|
|
$
|
(1,983
|
)
|
|
$
|
12,303
|
|
|
$
|
1,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
32,838
|
|
|
$
|
12,672
|
|
|
$
|
20,288
|
|
|
$
|
3,935
|
|
|
$
|
2,999
|
|
|
|
|
|
|
|
|
|
Net cash (used in) investing activities
|
|
|
(45,547
|
)
|
|
|
(24,947
|
)
|
|
|
(116,687
|
)
|
|
|
(10,601
|
)
|
|
|
(7,898
|
)
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
11,619
|
|
|
|
15,989
|
|
|
|
96,756
|
|
|
|
9,434
|
|
|
|
1,375
|
|
|
|
|
|
|
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
33,971
|
|
|
$
|
24,340
|
|
|
$
|
23,239
|
|
|
$
|
5,042
|
|
|
$
|
5,602
|
|
|
$
|
59,608
|
|
|
$
|
12,155
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Memorial
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
Partners LP
|
|
|
Our Predecessor
|
|
Pro Forma
|
|
|
Year Ended December 31,
|
|
As of March 31,
|
|
As of March 31,
|
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
2011
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital
|
|
$
|
(966
|
)
|
|
$
|
9,494
|
|
|
$
|
4,116
|
|
|
$
|
2,490
|
|
|
$
|
1,318
|
|
Total assets
|
|
|
145,529
|
|
|
|
146,153
|
|
|
|
248,540
|
|
|
|
245,042
|
|
|
|
435,107
|
|
Total debt
|
|
|
62,536
|
|
|
|
61,784
|
|
|
|
115,428
|
|
|
|
112,584
|
|
|
|
130,000
|
|
Partners capital
|
|
|
54,576
|
|
|
|
72,988
|
|
|
|
105,801
|
|
|
|
108,039
|
|
|
|
278,543
|
|
Non-GAAP Financial
Measure
We include in this prospectus the non-GAAP financial measure
Adjusted EBITDA and provide our calculation of Adjusted EBITDA
and a reconciliation of Adjusted EBITDA to net cash provided by
operating activities, our most directly comparable financial
measure calculated and presented in accordance with GAAP. We
define Adjusted EBITDA as net income (loss):
|
|
|
|
|
Interest expense, including realized and unrealized losses on
interest rate derivative contracts;
|
|
|
|
Income tax expense;
|
|
|
|
Depreciation, depletion and amortization;
|
|
|
|
Impairment of goodwill and long-lived assets (including oil and
natural gas properties);
|
|
|
|
Accretion of asset retirement obligations;
|
|
|
|
Unrealized losses on commodity derivative contracts;
|
|
|
|
Losses on sale of assets and other, net;
|
|
|
|
Unit-based compensation expenses;
|
|
|
|
Exploration costs; and
|
|
|
|
Other non-routine items that we deem appropriate.
|
|
|
|
|
|
Interest income;
|
|
|
|
Income tax benefit;
|
|
|
|
Unrealized gains on commodity derivative contracts;
|
|
|
|
Gains on sale of assets and other, net; and
|
|
|
|
Other non-routine items that we deem appropriate.
|
We expect that we will be required to comply with certain
Adjusted EBITDA-related metrics under our new revolving credit
facility.
Adjusted EBITDA will be used as a supplemental financial measure
by our management and by external users of our financial
statements, such as investors, commercial banks and others, to
assess:
|
|
|
|
|
our operating performance as compared to that of other companies
and partnerships in our industry, without regard to financing
methods, capital structure or historical cost basis; and
|
18
|
|
|
|
|
the ability of our assets to generate cash sufficient to pay
interest costs, support our indebtedness, and make distributions
on our units.
|
In addition, our management will use Adjusted EBITDA to evaluate
actual cash flow available to pay distributions to our
unitholders, develop existing reserves, or acquire additional
oil and natural gas properties.
Adjusted EBITDA should not be considered an alternative to net
income, operating income, cash flow from operating activities,
or any other measure of financial performance or liquidity
presented in accordance with GAAP. Our Adjusted EBITDA may not
be comparable to similarly titled measures of another company
because all companies may not calculate Adjusted EBITDA in the
same manner. The following table presents our calculation of
Adjusted EBITDA. The table below further presents a
reconciliation of Adjusted EBITDA to net cash flows provided by
operating activities, our most directly comparable GAAP
financial measure, for each of the periods indicated.
Calculation
of Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Memorial Production
|
|
|
|
|
|
|
Partners LP
|
|
|
|
Our Predecessor
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
Year
|
|
|
Three
|
|
|
|
|
|
|
|
|
|
Ended
|
|
|
Months
|
|
|
|
|
|
|
Three Months Ended
|
|
|
December
|
|
|
Ended
|
|
|
|
Year Ended December 31,
|
|
|
March 31,
|
|
|
31,
|
|
|
March 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Net income (loss)
|
|
$
|
21,085
|
|
|
$
|
1,106
|
|
|
$
|
(11,317
|
)
|
|
$
|
4,032
|
|
|
$
|
(1,983
|
)
|
|
$
|
12,303
|
|
|
$
|
1,863
|
|
Interest expense
|
|
|
3,138
|
|
|
|
2,937
|
|
|
|
4,438
|
|
|
|
606
|
|
|
|
1,035
|
|
|
|
4,365
|
|
|
|
1,092
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
225
|
|
|
|
|
|
|
|
|
|
|
|
225
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
12,353
|
|
|
|
15,226
|
|
|
|
20,066
|
|
|
|
4,352
|
|
|
|
4,450
|
|
|
|
34,772
|
|
|
|
7,026
|
|
Impairment
|
|
|
14,166
|
|
|
|
3,480
|
|
|
|
11,800
|
|
|
|
1,691
|
|
|
|
|
|
|
|
9,509
|
|
|
|
|
|
Accretion of asset retirement obligations
|
|
|
224
|
|
|
|
320
|
|
|
|
663
|
|
|
|
64
|
|
|
|
210
|
|
|
|
1,072
|
|
|
|
276
|
|
Unrealized (gains) losses on derivative instruments
|
|
|
(9,974
|
)
|
|
|
6,432
|
|
|
|
(2,674
|
)
|
|
|
(5,703
|
)
|
|
|
1,898
|
|
|
|
(2,674
|
)
|
|
|
1,898
|
|
Gain on sale of properties
|
|
|
(7,395
|
)
|
|
|
(7,851
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
Unit-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration costs
|
|
|
374
|
|
|
|
2,690
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
33,971
|
|
|
$
|
24,340
|
|
|
$
|
23,239
|
|
|
$
|
5,042
|
|
|
$
|
5,602
|
|
|
$
|
59,608
|
|
|
$
|
12,155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation
of Net Cash from Operating Activities to Adjusted
EBITDA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our Predecessor
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
March 31,
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
32,838
|
|
|
$
|
12,672
|
|
|
$
|
20,288
|
|
|
$
|
3,935
|
|
|
$
|
2,999
|
|
|
|
|
|
|
|
|
|
Changes in working capital
|
|
|
(1,979
|
)
|
|
|
8,840
|
|
|
|
(742
|
)
|
|
|
561
|
|
|
|
1,653
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
3,138
|
|
|
|
2,937
|
|
|
|
4,438
|
|
|
|
606
|
|
|
|
1,035
|
|
|
|
|
|
|
|
|
|
Amortization of deferred financing fees
|
|
|
(26
|
)
|
|
|
(109
|
)
|
|
|
(745
|
)
|
|
|
(60
|
)
|
|
|
(85
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
33,971
|
|
|
$
|
24,340
|
|
|
$
|
23,239
|
|
|
$
|
5,042
|
|
|
$
|
5,602
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
Summary
Reserve and Pro Forma Operating Data
The following tables present summary data with respect to our
estimated net proved oil and natural gas reserves and pro forma
operating data as of the dates presented.
The reserve estimates attributable to the Partnership Properties
at December 31, 2010 presented in the table below are based
on the following: (1) approximately 53% of the estimated
proved reserve volumes are based on a reserve report relating to
our South Texas properties prepared by the independent petroleum
engineers of NSAI; (2) approximately 35% of the estimated
proved reserve volumes are based on evaluations relating to
certain of our East Texas properties prepared by Memorial
Resources internal reserve engineers and audited by NSAI;
and (3) the remaining approximately 12% of the estimated
proved reserve volumes are based on a reserve report relating to
certain of our East Texas properties prepared by the independent
petroleum engineers of Miller and Lents. All of these reserve
estimates were prepared in accordance with the SECs rules
regarding oil and natural gas reserve reporting that are
currently in effect. The following tables also contain certain
summary unaudited information regarding production and sales of
oil and natural gas with respect to such properties.
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations,
Business and Properties Oil and Natural Gas
Data and Operations Properties Estimated
Proved Reserves and the reserve report and reserve audit
report summaries included in this prospectus in evaluating the
material presented below. The summaries of our reserve reports
are included as Appendices C, D and E of this prospectus.
Reserve
Data
|
|
|
|
|
|
|
Partnership
|
|
|
|
Properties as of
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
Estimated Proved Reserves
|
|
|
|
|
Oil (MBbls)
|
|
|
2,002
|
|
NGLs (MBbls)
|
|
|
4,502
|
|
Natural gas (MMcf)
|
|
|
285,676
|
|
|
|
|
|
|
Total (MMcfe)(1)
|
|
|
324,697
|
|
Proved developed (MMcfe)
|
|
|
264,572
|
|
Proved undeveloped (MMcfe)
|
|
|
60,125
|
|
Proved developed reserves as a percentage of total proved
reserves
|
|
|
81
|
%
|
Standardized measure (in millions)(2)(3)
|
|
$
|
359.2
|
|
Oil and Natural Gas Prices(4)
|
|
|
|
|
Oil WTI Posting (Plains) per Bbl
|
|
$
|
75.96
|
|
Natural gas NYMEXHenry Hub per MMBtu
|
|
$
|
4.38
|
|
|
|
|
(1) |
|
Determined using a ratio of six Mcf of natural gas to one Bbl of
oil, condensate or NGLs based on an approximate energy
equivalency. This is an energy content correlation and does not
reflect a value or price relationship between the commodities. |
|
(2) |
|
Standardized measure is the present value of estimated future
net revenues to be generated from the production of proved
reserves, determined in accordance with the rules and
regulations of the SEC without giving effect to non-property
related expenses, such as general and administrative expenses,
interest and income tax expenses, or to depreciation, depletion
and amortization. The future cash flows are discounted using an
annual discount rate of 10%. Because we are a limited
partnership, we are generally not subject to federal income
taxes and thus make no provision for federal income taxes in the
calculation of our standardized measure. Standardized measure
does not give effect to derivative transactions. We expect to
hedge a substantial portion of our future estimated production
from total proved producing reserves. For a description of our
expected commodity derivative contracts, please read
Managements Discussion and |
20
|
|
|
|
|
Analysis of Financial Condition and Results of
Operations Pro Forma Liquidity and Capital
Resources Commodity Derivative Contracts. |
|
(3) |
|
Because we are subject to Texas margin tax, our standardized
measure was negatively impacted by $5.0 million. |
|
(4) |
|
Our estimated net proved reserves and related standardized
measure were determined using index prices for oil and natural
gas, without giving effect to derivative contracts, held
constant throughout the life of the properties. These prices
were adjusted by lease for quality, transportation fees,
geographical differentials, marketing bonuses or deductions and
other factors affecting the price received at the wellhead. |
Pro
Forma Operating Data
|
|
|
|
|
|
|
|
|
|
|
Memorial Production
|
|
|
Partners LP
|
|
|
Pro Forma
|
|
|
|
|
Three Months
|
|
|
Year Ended
|
|
Ended
|
|
|
December 31,
|
|
March 31,
|
|
|
2010
|
|
2011
|
|
|
(Unaudited)
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
107
|
|
|
|
28
|
|
NGLs (MBbls)
|
|
|
272
|
|
|
|
56
|
|
Natural gas (MMcf)
|
|
|
16,713
|
|
|
|
3,897
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
18,985
|
|
|
|
4,399
|
|
Average net production (MMcfe/d)
|
|
|
52
|
|
|
|
49
|
|
Average sales price:(1)
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
74.35
|
|
|
$
|
90.11
|
|
NGLs (per Bbl)
|
|
$
|
37.41
|
|
|
$
|
43.76
|
|
Natural gas (per Mcf)
|
|
$
|
4.17
|
|
|
$
|
4.02
|
|
Average price per Mcfe
|
|
$
|
4.62
|
|
|
$
|
4.69
|
|
Average unit costs per Mcfe:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.21
|
|
|
$
|
1.52
|
|
Production and ad valorem taxes
|
|
$
|
0.39
|
|
|
$
|
0.39
|
|
General and administrative expenses
|
|
$
|
0.31
|
|
|
$
|
0.32
|
|
Depreciation, depletion and amortization
|
|
$
|
1.83
|
|
|
$
|
1.60
|
|
|
|
|
(1) |
|
Prices do not include the effects of derivative cash settlements. |
21
RISK
FACTORS
Limited partner interests are inherently different from the
capital stock of a corporation, although many of the business
risks to which we are subject are similar to those that would be
faced by a corporation engaged in a business similar to ours.
Prospective unitholders should carefully consider the following
risk factors together with all of the other information included
in this prospectus in evaluating an investment in our common
units.
If any of the following risks were actually to occur, our
business, financial condition or results of operations could be
materially adversely affected. In that case, we might not be
able to pay distributions on our common units, the trading price
of our common units could decline and our unitholders could lose
all or part of their investment.
Risks
Related to Our Business
We may
not have sufficient cash to pay the minimum quarterly
distribution on our common units, following the establishment of
cash reserves and payment of fees and expenses, including
payments to our general partner and its
affiliates.
We may not have sufficient available cash each quarter to pay
the minimum quarterly distribution of
$ per unit or any other amount.
Under the terms of our partnership agreement, the amount of cash
available for distribution will be reduced by our operating and
administrative expenses and the amount of any cash reserves
established by our general partner to provide for future
operations, future capital expenditures, including acquisitions
of additional oil and natural gas properties, future debt
service requirements and future cash distributions to our
unitholders. We intend to reserve a portion of our cash
generated from operations to develop our oil and natural gas
properties and to acquire additional oil and natural gas
properties to maintain and grow our oil and natural gas reserves.
The amount of cash we actually generate will depend upon
numerous factors related to our business that may be beyond our
control, including, among other things, the risks described in
this section. In addition, the actual amount of cash that we
will have available for distribution to our unitholders will
depend on other factors, including:
|
|
|
|
|
the amount of oil, natural gas and NGLs we produce;
|
|
|
|
the prices at which we sell our oil, natural gas and NGL
production;
|
|
|
|
the effectiveness of our commodity price hedging strategy;
|
|
|
|
the costs of developing, producing and transporting our oil and
natural gas assets, including costs attributable to governmental
regulation and taxation;
|
|
|
|
the level of our capital expenditures, including scheduled and
unexpected maintenance expenditures;
|
|
|
|
the cost of acquisitions;
|
|
|
|
our ability to borrow funds, whether under our new revolving
credit facility or otherwise, and to access capital markets;
|
|
|
|
prevailing economic conditions;
|
|
|
|
sources of cash used to fund acquisitions;
|
|
|
|
debt service requirements and restrictions on distributions
contained in our new revolving credit facility or future debt
agreements and other liabilities;
|
|
|
|
interest payments;
|
|
|
|
fluctuations in our working capital needs;
|
|
|
|
timing and collectability of receivables;
|
22
|
|
|
|
|
governmental regulations and taxation;
|
|
|
|
the amount of our operating expense and general and
administrative expenses, including reimbursements to Memorial
Resource in respect of those expenses;
|
|
|
|
the amount of cash reserves (which we expect to be substantial)
established by our general partner for the proper conduct of our
business and for capital expenditures to maintain our production
levels over the long-term; and
|
|
|
|
other business risks affecting our cash levels.
|
As a result of these factors, the amount of cash we distribute
to our unitholders may fluctuate significantly from quarter to
quarter and may be less than the minimum quarterly distribution
that we expect to distribute. For a description of additional
restrictions and factors that may affect our ability to make
cash distributions to our unitholders, please read Our
Cash Distribution Policy and Restrictions on Distributions.
Further, the amount of cash we have available for distribution
depends primarily on our cash flow, including cash from
financial reserves and working capital or other borrowings, and
not solely on profitability, which will be affected by non-cash
items. As a result, we may make cash distributions during
periods when we record losses for financial accounting purposes
and may not make cash distributions during periods when we
record net income for financial accounting purposes.
If the
underwriters exercise their option to purchase additional common
units in full, we would not have generated sufficient available
cash on a pro forma basis to have paid the minimum quarterly
distribution on our subordinated units for the twelve months
ended March 31, 2011.
If we had completed the formation transactions contemplated in
this prospectus and the acquisition of all of the Partnership
Properties on April 1, 2010, our unaudited pro forma
available cash generated during the twelve months ended
March 31, 2011 would have been approximately
$40.6 million. As a result, assuming the underwriters
exercise their option to purchase additional common units in
full, this amount would have been sufficient to make a cash
distribution for the twelve months ended March 31, 2011 at
the minimum quarterly distribution of
$ per unit per quarter on all
of our common units and general partner units, but only a
quarterly distribution of
$ on all of our subordinated
units during that period. For a calculation of our ability to
have made distributions to our unitholders based on our pro
forma results of operations for the twelve months ended
March 31, 2011, please read Our Cash Distribution
Policy and Restrictions on Distributions Unaudited
Pro Forma Available Cash for the Year Ended December 31,
2010 and Twelve Months Ended March 31, 2011.
The
assumptions underlying the forecast of cash available for
distribution that we include in Our Cash Distribution
Policy and Restrictions on Distributions are inherently
uncertain and are subject to significant business, economic,
financial, legal, regulatory and competitive risks and
uncertainties that could cause actual results to differ
materially from those estimated.
The forecast of cash available for distribution set forth in
Our Cash Distribution Policy and Restrictions on
Distributions includes our forecast of our results of
operations, Adjusted EBITDA and cash available for distribution
for the twelve months ending June 30, 2012. Our ability to
pay the full minimum quarterly distribution in the forecast
period is based on a number of assumptions that may not prove to
be correct and that are discussed in Our Cash Distribution
Policy and Restrictions on Distributions. Our financial
forecast has been prepared by management, and we have neither
received nor requested an opinion or report on it from our or
any other independent auditor. Furthermore, the forecasted
results of operations, Adjusted EBITDA and cash available for
distribution are in part based on our reserve reports, which
reflect assumptions about development, production, oil and
natural gas prices and capital expenditures, and other
assumptions about expenses, borrowings and other matters that
are inherently uncertain and are subject to significant
business, economic, financial, legal, regulatory and competitive
risks and uncertainties that could cause actual results to
differ materially from those estimated. If any of the
assumptions underlying our forecast prove to be inaccurate, our
actual results may differ materially from those set forth in our
estimates, and we may be
23
unable to pay all or part of the minimum quarterly distribution
on our common units, subordinated units or general partner
units, in which event the market price of our common units may
decline materially.
Our
estimated oil and natural gas reserves will naturally decline
over time, and it is unlikely that we will be able to sustain
distributions at the level of our minimum quarterly distribution
without making accretive acquisitions or substantial capital
expenditures that maintain our asset base.
Our future oil and natural gas reserves, production volumes,
cash flow and ability to make distributions to our unitholders
depend on our success in developing and exploiting our current
reserves efficiently and finding or acquiring additional
recoverable reserves economically. Based on our reserve reports,
the average decline rate for our existing proved developed
producing reserves is approximately 9% for 2011, approximately
9% compounded average decline for the subsequent four years and
approximately 8% thereafter. Actual decline rates may vary from
these projected decline rates. We may be unable to develop, find
or acquire additional reserves to replace our current and future
production at acceptable costs, which would adversely affect our
business, financial condition and results of operations and
reduce cash available for distribution to our unitholders.
We will need to make substantial capital expenditures to
maintain our asset base, which will reduce our cash available
for distribution. For example, we plan to spend approximately
$9.2 million for capital expenditures for the twelve months
ending June 30, 2012 based on our reserve reports, which
amount spent annually we believe will also enable us to maintain
our targeted average net production from our assets of
49 MMcfe/d through December 31, 2015. We may use the
reserved cash to reduce indebtedness until we make the capital
expenditures. Over a longer period of time, if we do not set
aside sufficient cash reserves or make sufficient expenditures
to maintain our asset base, we will be unable to pay
distributions at the minimum quarterly distribution from cash
generated from operations and would therefore expect to reduce
our distributions. If our reserves decrease and we do not reduce
our distribution, then a portion of the distribution may be
considered a return of part of a unitholders investment in
us as opposed to a return on his investment. If we do not make
sufficient growth capital expenditures, we will be unable to
sustain our business operations and would therefore expect to
reduce our distributions to our unitholders. We have not
forecasted any growth capital expenditures for the twelve months
ending June 30, 2012, based on our reserve reports.
None
of the proceeds of this offering will be used to maintain or
grow our asset base or be reserved for future
distributions.
None of the proceeds of this offering will be used to maintain
or grow our asset base, which may be necessary to cover future
distributions to our unitholders, and none of the proceeds will
be reserved for future distributions to our unitholders. The
proceeds of this offering, together with borrowings under our
new revolving credit facility, will be used as partial
consideration for the Partnership Properties, which will be
contributed to us by Memorial Resource at the closing of this
offering.
Our
acquisition and development operations will require substantial
capital expenditures, and we expect to fund these capital
expenditures using cash generated from our operations,
additional borrowings or the issuance of additional partnership
interests, or some combination thereof, which could adversely
affect our ability to pay distributions at the then-current
distribution rate or at all.
The oil and natural gas industry is capital intensive. We expect
to make substantial growth capital expenditures in our business
for the development, production and acquisition of oil and
natural gas reserves. These expenditures will reduce the amount
of cash available for distribution to our unitholders. We intend
to finance our future growth capital expenditures with cash
flows from operations, borrowings under our new revolving credit
facility and the issuance of debt and equity securities.
Our cash flows from operations and access to capital are subject
to a number of variables, including:
|
|
|
|
|
our estimated proved oil and natural gas reserves;
|
|
|
|
the amount of oil, natural gas and NGL we produce;
|
24
|
|
|
|
|
the prices at which we sell our production;
|
|
|
|
the costs of developing, producing and transporting our oil and
natural gas assets, including costs attributable to governmental
regulation and taxation;
|
|
|
|
our ability to acquire, locate and produce new reserves;
|
|
|
|
fluctuations in our working capital needs;
|
|
|
|
interest payments and debt service requirements;
|
|
|
|
prevailing economic conditions;
|
|
|
|
the ability and willingness of banks to lend to us; and
|
|
|
|
our ability to access the equity and debt capital markets.
|
The use of cash generated from operations to fund growth capital
expenditures will reduce cash available for distribution to our
unitholders. If the borrowing base under our new revolving
credit facility or our revenues decrease as a result of lower
oil or natural gas prices, operating difficulties, declines in
estimated reserves or production or for any other reason, we may
have limited ability to obtain the capital necessary to sustain
our operations at current levels. If additional capital is
needed to fund our growth capital expenditures, our ability to
access the capital markets for future equity or debt offerings
may be limited by our financial condition at the time of any
such financing or offering and the covenants in our new
revolving credit facility, as well as by adverse market
conditions resulting from, among other things, general economic
conditions and contingencies and uncertainties that are beyond
our control.
Our failure to obtain the funds for necessary future growth
capital expenditures could have a material adverse effect on our
business, results of operations, financial condition and ability
to pay distributions to our unitholders. Even if we are
successful in obtaining the necessary funds, the terms of such
financings could limit our ability to pay distributions to our
unitholders. In addition, incurring additional debt may
significantly increase our interest expense and financial
leverage, and issuing additional partnership interests may
result in significant unitholder dilution, thereby increasing
the aggregate amount of cash required to maintain the
then-current distribution rate, which could adversely affect our
ability to pay distributions to our unitholders at the
then-current distribution rate or at all.
Oil
and natural gas prices are very volatile, and a decline in oil
or natural gas prices will cause a decline in our cash flow from
operations, which could cause us to reduce our distributions or
cease paying distributions altogether.
The oil and natural gas markets are very volatile, and we cannot
predict future oil and natural gas prices. Prices for oil and
natural gas may fluctuate widely in response to relatively minor
changes in the supply of and demand for oil and natural gas,
market uncertainty and a variety of additional factors that are
beyond our control, such as:
|
|
|
|
|
regional, domestic and foreign supply and perceptions of supply
of oil and natural gas;
|
|
|
|
the level of demand and perceptions of demand for oil and
natural gas;
|
|
|
|
weather conditions, seasonal trends and the occurrence of
natural disasters;
|
|
|
|
anticipated future prices of oil and natural gas and other
commodities;
|
|
|
|
overall domestic and global economic conditions;
|
|
|
|
political and economic conditions in oil and natural gas
producing countries globally, including terrorist attacks, civil
unrest, political demonstrations, mass strikes or additional
outbreaks of armed hostilities or other crises and threats,
escalation of military activity in response to such activities
or acts of war;
|
|
|
|
actions of the Organization of the Petroleum Exporting
Countries, or OPEC, and other state-controlled oil companies
relating to oil price and production controls;
|
25
|
|
|
|
|
the effect of increasing liquefied natural gas, or LNG,
deliveries to and exports from the United States;
|
|
|
|
the impact of the U.S. dollar exchange rates on oil and
natural gas prices;
|
|
|
|
technological advances affecting energy supply and energy
consumption;
|
|
|
|
domestic and foreign governmental regulations and taxation;
|
|
|
|
the impact of energy conservation efforts;
|
|
|
|
the proximity, capacity, cost and availability of oil and
natural gas pipelines and other transportation facilities;
|
|
|
|
the availability of refining capacity; and
|
|
|
|
the price and availability of alternative fuels.
|
In the past, oil and natural gas prices have been extremely
volatile, and we expect this volatility to continue. For
example, for the five years ended December 31, 2010, the
NYMEXWTI oil price ranged from a high of $145.29 per Bbl
to a low of $31.41 per Bbl, while the NYMEXHenry Hub
natural gas price ranged from a high of $13.31 per MMBtu to a
low of $1.83 per MMBtu. Such volatility, particularly in natural
gas prices, may affect our amount of net estimated proved
reserves and will affect the standardized measure of discounted
future net cash flows of our net estimated proved reserves.
Because 88% of our estimated proved reserves as of
December 31, 2010 are natural gas, we are acutely sensitive
to changes in natural gas prices.
Natural gas prices are closely linked to supply of natural gas
and consumption patterns in the United States of the electric
power generation industry and certain industrial and residential
patterns where natural gas is the principal fuel. The domestic
natural gas industry continues to face concerns of oversupply
due to the success of new plays and continued drilling in these
plays, despite lower natural gas prices, to meet drilling
commitments.
Our revenue, profitability and cash flow depend upon the prices
of and demand for oil and natural gas, and a drop in prices can
significantly affect our financial results and impede our
growth. In particular, declines in commodity prices will:
|
|
|
|
|
limit our ability to enter into hedging contracts at attractive
prices;
|
|
|
|
reduce the value and quantities of our reserves, because
declines in oil and natural gas prices would reduce the amount
of oil and natural gas that we can economically produce;
|
|
|
|
reduce the amount of cash flow available for capital
expenditures;
|
|
|
|
limit our ability to borrow money or raise additional
capital; and
|
|
|
|
impair our ability to pay distributions to our unitholders.
|
If we raise our distribution levels in response to increased
cash flow during periods of relatively high commodity prices, we
may not be able to sustain those distribution levels during
subsequent periods of lower commodity prices.
An
increase in the differential between the NYMEX or other
benchmark prices of oil and natural gas and the wellhead price
we receive for our production could significantly reduce our
cash available for distribution and adversely affect our
financial condition.
The prices that we receive for our oil and natural gas
production sometimes reflect a discount to the relevant
benchmark prices, such as NYMEX, that are used for calculating
hedge positions. The difference between the benchmark price and
the price we receive is called a basis differential. Increases
in the basis differential between the benchmark prices for oil
and natural gas and the wellhead price we receive could
significantly reduce our cash available for distribution to our
unitholders and adversely affect our financial condition. We do
not have or plan to have any commodity derivative contracts
covering the amount of the
26
basis differentials we experience in respect of our production.
As such, we will be exposed to any increase in such
differentials, which could adversely affect our results of
operations.
Future
commodity price declines, increased capital costs, changes in
well performance, delays in asset development or deterioration
of drilling results may result in a write-down of our asset
carrying values, which could adversely affect our results of
operations.
The value of our assets depend substantially on oil and natural
gas prices. Declines in these prices as well as increases in
development costs, changes in well performance, delays in asset
development or deterioration of drilling results may result in
our having to make substantial downward adjustments to our
estimated proved reserves, and accounting rules may require us
to write down, as a non-cash charge to earnings, the carrying
value of our oil and natural gas properties for impairments. We
capitalize costs to acquire, find and develop our oil and
natural gas properties under the successful efforts accounting
method. If net capitalized costs of our oil and natural gas
properties exceed fair value, we must charge the amount of the
excess to earnings. Such a charge would not impact cash flow
from operating activities, but it would reduce partners
equity on our balance sheet. We review the carrying value of our
properties annually and at any time when events or circumstances
indicate a review is necessary, based on estimated prices as of
the end of the reporting period. The carrying value of oil and
natural gas properties is computed on a
field-by-field
basis. Once incurred, a write-down of oil and natural gas
properties is not reversible at a later date even if oil or
natural gas prices increase. It is possible that declines in
commodity prices could prompt an impairment in the future, which
could adversely affect our results of operations in the period
incurred.
Our
hedging strategy may be ineffective in removing the impact of
commodity price volatility from our cash flows, which could
result in financial losses or could reduce our income, which may
adversely affect our ability to pay distributions to our
unitholders.
Memorial Resource will contribute to us at the closing of this
offering, and we expect to enter into in the future commodity
derivative contracts for a significant portion of our estimated
production from total proved developed producing reserves that
could result in both realized and unrealized hedging losses. We
also expect to adopt a hedging policy designed to reduce the
impact to our cash flows from commodity price volatility. Under
this policy, we intend to enter into commodity derivative
contracts covering approximately 65% to 85% of our estimated
production from total proved developed producing reserves over a
three-to-five
year period at any given point of time. We may, however, from
time to time hedge more or less than this approximate range. Our
hedging strategy and future hedging transactions will be
determined at the discretion of our general partner, which is
not under any obligation to enter into commodity derivative
contracts covering any specific portion of our production. We
expect that our new revolving credit facility, will, among other
things, limit the amount of commodity derivative contracts we
can enter into.
The prices at which we enter into commodity derivative contracts
covering our production in the future will be dependent upon oil
and natural gas prices at the time we enter into these
transactions, which may be substantially higher or lower than
current or future oil and natural gas prices. Accordingly, our
price hedging strategy may not protect us from significant
declines in oil and natural gas prices received for our future
production. Conversely, our hedging strategy may limit our
ability to realize incremental cash flows from commodity price
increases.
Our
hedging activities could result in cash losses, could reduce our
cash available for distributions and may limit potential
gains.
Many of the derivative contracts to which we will be a party
will require us to make cash payments to the extent the
applicable index exceeds a predetermined price, thereby limiting
our ability to realize the benefit of increases in oil and
natural gas prices. If our actual production and sales for any
period are less than our hedged production and sales for that
period (including reductions in production due to operational
delays) or if we are unable to perform our drilling activities
as planned, we might be forced to satisfy all or a portion of
our hedging obligations without the benefit of the cash flow
from our sale of the underlying physical commodity, which may
materially impact our liquidity.
27
Our
hedging transactions expose us to counterparty credit
risk.
Our hedging transactions expose us to risk of financial loss if
a counterparty fails to perform under a derivative contract.
Disruptions in the financial markets could lead to sudden
changes in a counterpartys liquidity, which could impair
its ability to perform under the terms of the derivative
contract. We are unable to predict sudden changes in a
counterpartys creditworthiness or ability to perform under
contracts with us. Even if we do accurately predict sudden
changes, our ability to mitigate that risk may be limited
depending upon market conditions.
Our
estimated proved reserves and future production rates are based
on many assumptions that may prove to be inaccurate. Any
material inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and present
value of our estimated reserves.
Numerous uncertainties are inherent in estimating quantities of
oil and natural gas reserves and future production. It is not
possible to measure underground accumulations of oil or natural
gas in an exact way. Oil and natural gas reserve engineering is
complex, requiring subjective estimates of underground
accumulations of oil and natural gas and assumptions concerning
future oil and natural gas prices, future production levels and
operating and development costs. In estimating our level of oil
and natural gas reserves, we and our independent reserve
engineers make certain assumptions that may prove to be
incorrect, including assumptions relating to:
|
|
|
|
|
the level of oil and natural gas prices;
|
|
|
|
future production levels;
|
|
|
|
capital expenditures;
|
|
|
|
operating and development costs;
|
|
|
|
the effects of regulation;
|
|
|
|
the accuracy and reliability of the underlying engineering and
geologic data; and
|
|
|
|
the availability of funds.
|
If these assumptions prove to be incorrect, our estimates of
proved reserves, the economically recoverable quantities of oil
and natural gas attributable to any particular group of
properties, the classifications of reserves based on risk of
recovery and our estimates of the future net cash flows from our
estimated proved reserves could change significantly. For
example, if the prices used in our reserve reports had been
$10.00 less per barrel for oil and $1.00 less per MMBtu for
natural gas, then the standardized measure of our estimated
proved reserves as of that date on a pro forma basis, excluding
the effects of our commodity derivative contracts, would have
decreased by $127.2 million, from $359.2 million to
$232.0 million.
Our standardized measure is calculated using unhedged natural
gas, oil and NGL prices and is determined in accordance with the
rules and regulations of the SEC. Over time, we may make
material changes to reserve estimates to take into account
changes in our assumptions and the results of actual development
and production.
The reserve estimates we make for wells or fields that do not
have a lengthy production history are less reliable than
estimates for wells or fields with lengthy production histories.
A lack of production history may contribute to inaccuracy in our
estimates of proved reserves, future production rates and the
timing of development expenditures.
The
standardized measure of our estimated proved reserves is not
necessarily the same as the current market value of our
estimated proved oil and natural gas reserves.
The standardized measure of our estimated proved reserves is not
necessarily the same as the current market value of our
estimated proved oil and natural gas reserves. We base the
estimated discounted future net cash flows from our estimated
proved reserves on prices and costs in effect as of the date of
the estimate.
28
However, actual future net cash flows from our oil and natural
gas properties also will be affected by factors such as:
|
|
|
|
|
the actual prices we receive for natural gas, oil and NGLs;
|
|
|
|
our actual operating costs in producing natural gas, oil and
NGLs;
|
|
|
|
the amount and timing of actual production;
|
|
|
|
the amount and timing of our capital expenditures;
|
|
|
|
the supply of and demand for natural gas, oil and NGLs; and
|
|
|
|
changes in governmental regulations or taxation.
|
The timing of both our production and our incurrence of expenses
in connection with the development and production of oil and
natural gas properties will affect the timing of actual future
net cash flows from estimated proved reserves, and thus their
actual present value. In addition, the 10% discount factor we
use when calculating discounted future net cash flows in
compliance with Accounting Standards Codification 932,
Extractive Activities Oil and Gas, may
not be the most appropriate discount factor based on interest
rates in effect from time to time and risks associated with us
or the oil and natural gas industry in general.
Developing
and producing oil and natural gas are costly and high-risk
activities with many uncertainties that could adversely affect
our financial condition or results of operations and, as a
result, our ability to pay distributions to our
unitholders.
The cost of developing, completing and operating a well is often
uncertain, and cost factors can adversely affect the economics
of a well. Our efforts will be uneconomical if we drill dry
holes or wells that are productive but do not produce as much
oil and natural gas as we had estimated. Furthermore, our
development and production operations may be curtailed, delayed
or canceled as a result of other factors, including:
|
|
|
|
|
high costs, shortages or delivery delays of rigs, equipment,
labor or other services;
|
|
|
|
composition of sour natural gas, including sulfur and mercaptan
content;
|
|
|
|
unexpected operational events and conditions;
|
|
|
|
reductions in oil and natural gas prices;
|
|
|
|
increases in severance taxes;
|
|
|
|
adverse weather conditions and natural disasters;
|
|
|
|
facility or equipment malfunctions and equipment failures or
accidents, including acceleration of deterioration of our
facilities and equipment due to the highly corrosive nature of
sour natural gas;
|
|
|
|
title problems;
|
|
|
|
pipe or cement failures, casing collapses or other downhole
failures;
|
|
|
|
compliance with ever-changing environmental and other
governmental requirements;
|
|
|
|
environmental hazards, such as natural gas leaks, oil spills,
salt water spills, pipeline ruptures and discharges of toxic
gases;
|
|
|
|
lost or damaged oilfield development and service tools;
|
|
|
|
unusual or unexpected geological formations and pressure or
irregularities in formations;
|
|
|
|
loss of drilling fluid circulation;
|
|
|
|
fires, blowouts, surface craterings and explosions;
|
|
|
|
uncontrollable flows of oil, natural gas or well fluids;
|
29
|
|
|
|
|
loss of leases due to incorrect payment of royalties; and
|
|
|
|
other hazards, including those associated with sour natural gas
such as an accidental discharge of hydrogen sulfide gas, that
could also result in personal injury and loss of life, pollution
and suspension of operations.
|
If any of these factors were to occur with respect to a
particular field, we could lose all or a part of our investment
in the field, or we could fail to realize the expected benefits
from the field, either of which could materially and adversely
affect our revenue and cash available for distribution to our
unitholders.
Additionally, drilling, transportation and processing of
hydrocarbons bear an inherent risk of loss of containment.
Potential consequences include loss of reserves, loss of
production, loss of economic value associated with the affected
wellbore, contamination of soil, ground water, and surface
water, as well as potential fines, penalties or damages
associated with any of the foregoing consequences.
Many
of our properties are in areas that may have been partially
depleted or drained by offset wells.
Many of our properties are in areas that may have already been
partially depleted or drained by earlier offset drilling. The
owners of leasehold interests lying contiguous or adjacent to or
adjoining any of our properties could take actions, such as
drilling additional wells, that could adversely affect our
operations. When a new well is completed and produced, the
pressure differential in the vicinity of the well causes the
migration of reservoir fluids towards the new wellbore (and
potentially away from existing wellbores). As a result, the
drilling and production of these potential locations could cause
a depletion of our proved reserves, and may inhibit our ability
to further exploit and develop our reserves.
Our
expectations for future development activities are planned to be
realized over several years, making them susceptible to
uncertainties that could materially alter the occurrence or
timing of such activities.
We have identified drilling, recompletion and development
locations and prospects for future drilling, recompletion and
development. These drilling, recompletion and development
locations represent a significant part of our future drilling
and enhanced recovery opportunity plans. Our ability to drill,
recomplete and develop these locations depends on a number of
factors, including the availability of capital, seasonal
conditions, regulatory approvals, negotiation of agreements with
third parties, commodity prices, costs, the generation of
additional seismic or geological information, the availability
of drilling rigs, and drilling results. Because of these
uncertainties, we cannot be certain of the timing of these
activities or that they will ultimately result in the
realization of estimated proved reserves or meet our
expectations for success. As such, our actual drilling and
enhanced recovery activities may materially differ from our
current expectations, which could have a significant adverse
effect on our estimated reserves, financial condition and
results of operations.
Shortages
of rigs, equipment and crews could delay our operations and
reduce our cash available for distribution to our
unitholders.
Higher oil and natural gas prices generally increase the demand
for rigs, equipment and crews and can lead to shortages of, and
increasing costs for, development equipment, services and
personnel. Shortages of, or increasing costs for, experienced
development crews and oil field equipment and services could
restrict Memorial Resources ability to drill the wells and
conduct the operations that it currently has planned relating to
the fields where the Partnership Properties are located. Any
delay in the development of new wells or a significant increase
in development costs could reduce our revenues and reduce our
cash available for distribution to our unitholders.
30
If we
do not make acquisitions on economically acceptable terms, our
future growth and ability to pay or increase distributions will
be limited.
Our ability to grow and to increase distributions to our
unitholders depends in part on our ability to make acquisitions
that result in an increase in available cash per unit. We may be
unable to make such acquisitions because we are:
|
|
|
|
|
unable to identify attractive acquisition candidates or
negotiate acceptable purchase contracts with their owners;
|
|
|
|
unable to obtain financing for such acquisitions on economically
acceptable terms; or
|
|
|
|
outbid by competitors.
|
If we are unable to acquire properties containing estimated
proved reserves, our total level of estimated proved reserves
will decline as a result of our production, and we will be
limited in our ability to increase or possibly even to maintain
our level of cash distributions to our unitholders.
Any
acquisitions we complete will be subject to substantial risks
that could reduce our ability to make distributions to
unitholders.
Even if we do make acquisitions that we believe will increase
available cash per unit, these acquisitions may nevertheless
result in a decrease in available cash per unit. Any acquisition
involves potential risks, including, among other things:
|
|
|
|
|
mistaken assumptions about estimated proved reserves, future
production, revenues, capital expenditures, operating expenses
and costs, including synergies;
|
|
|
|
an inability to successfully integrate the assets or businesses
we acquire;
|
|
|
|
a decrease in our liquidity by using a significant portion of
our available cash or borrowing capacity to finance acquisitions;
|
|
|
|
a significant increase in our interest expense or financial
leverage if we incur additional debt to finance acquisitions;
|
|
|
|
the assumption of unknown liabilities, losses or costs for which
we are not indemnified or for which any indemnity we receive is
inadequate;
|
|
|
|
the diversion of managements attention from other business
concerns;
|
|
|
|
mistaken assumptions about the overall cost of equity or debt;
|
|
|
|
an inability to hire, train or retain qualified personnel to
manage and operate our growing business and assets;
|
|
|
|
facts and circumstances that could give rise to significant cash
and certain non-cash charges; and
|
|
|
|
customer or key employee losses at the acquired businesses.
|
Further, we may in the future expand our operations into new
geographic areas with operating conditions and a regulatory
environment that may not be as familiar to us as our existing
core operating areas. As a result, we may encounter obstacles
that may cause us not to achieve the expected results of any
such acquisitions, and any adverse conditions, regulations or
developments related to any assets acquired in new geographic
areas may have a negative impact on our operations and financial
condition.
Our decision to acquire a property will depend in part on the
evaluation of data obtained from production reports and
engineering studies, geophysical and geological analyses and
seismic data and other information, the results of which are
often inconclusive and subject to various interpretations. Our
reviews of acquired properties are inherently incomplete because
it generally is not feasible to perform an in-depth review of
the individual properties involved in each acquisition, given
time constraints imposed by sellers. Even a detailed review of
records and properties may not necessarily reveal existing or
potential problems, nor will it permit a
31
buyer to become sufficiently familiar with the properties to
assess fully their deficiencies and potential. Inspections may
not always be performed on every well, and environmental
problems, such as groundwater contamination, are not necessarily
observable even when an inspection is undertaken.
If we consummate any future acquisitions, our capitalization and
results of operations may change significantly, and unitholders
will not have the opportunity to evaluate the economic,
financial and other relevant information that we will consider
in determining the application of funds and other resources to
such acquisitions.
If our acquisitions do not generate the expected increases in
available cash per unit, our ability to make distributions to
our unitholders could be reduced.
Adverse
developments in our operating areas would reduce our ability to
make distributions to our unitholders.
Our properties are located in South and East Texas. An adverse
development in the oil and natural gas business of these
geographic areas, such as in our ability to attract and retain
field personnel, could have an impact on our results of
operations and cash available for distribution to our
unitholders.
We may
experience a financial loss if Memorial Resource is unable to
sell, or receive payment for, a significant portion of our oil
and natural gas production.
Under our omnibus agreement, Memorial Resource will handle sales
of our natural gas, oil and NGL production on our behalf, which
will depend upon the demand for natural gas, oil and NGLs from
potential purchasers of our production.
In recent years, a number of energy marketing and trading
companies have discontinued their marketing and trading
operations, which has significantly reduced the number of
potential purchasers for our production. This reduction in
potential customers has reduced overall market liquidity. If any
one or more of our significant customers reduces the volume of
oil and natural gas production it purchases and other customers
to sell those volumes to are unable to be found, then the volume
of our production sold on our behalf could be reduced, and we
could experience a material decline in cash available for
distribution.
In addition, a failure by any of these companies, or any
purchasers of our production, to perform their payment
obligations to us could have a material adverse effect on our
results of operation. To the extent that purchasers of our
production rely on access to the credit or equity markets to
fund their operations, there could be an increased risk that
those purchasers could default in their contractual obligations
to us. If for any reason we were to determine that it was
probable that some or all of the accounts receivable from any
one or more of the purchasers of our production were
uncollectible, we would recognize a charge in the earnings of
that period for the probable loss and could suffer a material
reduction in our liquidity and ability to make distributions to
our unitholders.
We may
be unable to compete effectively with larger companies, which
may adversely affect our ability to generate sufficient revenue
to allow us to pay distributions to our
unitholders.
The oil and natural gas industry is intensely competitive with
respect to acquiring prospects and productive properties,
marketing oil and natural gas, and securing equipment and
trained personnel. Many of our competitors are large independent
oil and natural gas companies and other publicly traded limited
partnerships that possess and employ financial, technical and
personnel resources substantially greater than ours and Memorial
Resources. Those entities may be able to develop and
acquire more properties than our financial or personnel
resources permit. Our ability to acquire additional properties
and to discover reserves in the future will depend on our
ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment.
Many of our larger competitors not only drill for and produce
oil and natural gas but also carry on refining operations and
market petroleum and other products on a regional, national or
worldwide basis. These companies may be able to pay more for oil
and natural gas properties and evaluate, bid for and purchase a
greater number of properties than our financial, technical or
personnel resources permit. In addition, there is substantial
competition for investment capital in the oil and natural gas
32
industry. These larger companies may have a greater ability to
continue development activities during periods of low oil and
natural gas prices and to absorb the burden of present and
future federal, state, local and other laws and regulations.
Furthermore, we may not be able to aggregate sufficient
quantities of production to compete with larger companies that
are able to sell greater volumes of production to
intermediaries, thereby reducing the realized prices
attributable to our production. Any inability to compete
effectively with larger companies could have a material adverse
impact on our business activities, financial condition and
results of operations and our ability to make distributions to
our unitholders.
We may
incur substantial additional debt to enable us to pay our
quarterly distributions, which may negatively affect our ability
to pay future distributions or execute our business
plan.
We may be unable to pay the minimum quarterly distribution or
the then-current distribution rate without borrowing under our
new revolving credit facility or otherwise. If we borrow to pay
distributions to our unitholders, we would be distributing more
cash than we are generating from our operations on a current
basis, which would mean that we are using a portion of our
borrowing capacity under our new revolving credit facility,
directly or indirectly, to pay distributions to our unitholders
rather than to maintain or expand our operations. If we use
borrowings to pay distributions to our unitholders for an
extended period of time rather than to fund capital expenditures
and other activities relating to our operations, we may be
unable to maintain or grow our business. Such a curtailment of
our business activities, combined with our payment of principal
and interest on our future indebtedness incurred to pay these
distributions, will reduce our cash available for distribution
on our units and will have a material adverse effect on our
business, financial condition and results of operations. If we
borrow to pay distributions to our unitholders during periods of
low commodity prices and commodity prices remain low, we may
have to reduce our distribution to our unitholders to avoid
excessive leverage.
Our
future debt levels may limit our ability to obtain additional
financing and pursue other business opportunities.
After giving effect to this offering and the formation
transactions, we estimate that we would have had approximately
$130.0 million of debt outstanding on a pro forma basis as
of March 31, 2011. Following the consummation of this
offering, we expect that we will have the ability to incur debt,
including under our new revolving credit facility, subject to
anticipated borrowing base limitations in our revolving credit
facility. The level of our future indebtedness could have
important consequences to us, including:
|
|
|
|
|
our ability to obtain additional financing, if necessary, for
working capital, capital expenditures, acquisitions or other
purposes may be impaired or such financing may not be available
on favorable terms;
|
|
|
|
covenants contained in our new revolving credit facility and
future debt arrangements will require us to meet financial tests
that may affect our flexibility in planning for and reacting to
changes in our business, including possible acquisition
opportunities;
|
|
|
|
we may need a substantial portion of our cash flow to make
principal and interest payments on our indebtedness, reducing
the funds that would otherwise be available for operations,
future business opportunities and distributions to our
unitholders; and
|
|
|
|
our debt level will make us more vulnerable than our competitors
with less debt to competitive pressures or a downturn in our
business or the economy generally.
|
Our ability to service our indebtedness will depend upon, among
other things, our future financial and operating performance,
which will be affected by prevailing economic conditions and
financial, business, regulatory and other factors, many of which
are beyond our control. If our operating results are not
sufficient to service our current or future indebtedness, we
will be forced to take actions such as reducing distributions to
our unitholders, reducing or delaying business activities,
acquisitions, investments
and/or
capital expenditures, selling assets, restructuring or
refinancing our indebtedness or seeking additional equity
capital
33
or bankruptcy protection. We may be unable to effect any of
these remedies on satisfactory terms or at all, which may have
an adverse effect on our ability to reduce cash distributions.
Our
new revolving credit facility will have restrictions and
financial covenants that may restrict our business and financing
activities and our ability to pay distributions to our
unitholders.
The operating and financial restrictions and covenants in our
new revolving credit facility will, and any future financing
agreements may, restrict our ability to finance future
operations or capital needs or to engage, expand or pursue our
business activities or to pay distributions to our unitholders.
Please read Managements Discussion and Analysis of
Financial Condition and Results of Operations Pro
Forma Liquidity and Capital Resources New Revolving
Credit Facility. Our ability to comply with these
restrictions and covenants is uncertain and will be affected by
the levels of cash flow from our operations and other events or
circumstances beyond our control. If market or other economic
conditions deteriorate, our ability to comply with these
covenants may be impaired. If we violate any provisions of our
new revolving credit facility that are not cured or waived
within the appropriate time periods provided in our revolving
credit facility, a significant portion of our indebtedness may
become immediately due and payable, our ability to make
distributions to our unitholders will be inhibited and our
lenders commitment to make further loans to us may
terminate. We might not have, or be able to obtain, sufficient
funds to make these accelerated payments. In addition, our
obligations under our new revolving credit facility will be
secured by substantially all of our assets, and if we are unable
to repay our indebtedness under our new revolving credit
facility, the lenders could seek to foreclose on our assets.
We anticipate that our new revolving credit facility will be
reserve-based, and thus we will be permitted to borrow under our
new revolving credit facility in an amount up to the borrowing
base, which is primarily based on the estimated value of our oil
and natural gas properties and our commodity derivative
contracts as determined semi-annually by our lenders in their
sole discretion. Our borrowing base will be subject to
redetermination on a semi-annual basis based on an engineering
report with respect to our estimated natural gas, oil and NGL
reserves, which will take into account the prevailing natural
gas, oil and NGL prices at such time, as adjusted for the impact
of our commodity derivative contracts. In the future, we may be
unable to access sufficient capital under our new revolving
credit facility as a result of (i) a decrease in our
borrowing base due to a subsequent borrowing base
redetermination, or (ii) an unwillingness or inability on
the part of our lenders to meet their funding obligations.
A future decline in commodity prices could result in a
redetermination that lowers our borrowing base in the future
and, in such case, we could be required to repay any
indebtedness in excess of the borrowing base, or we could be
required to pledge other oil and natural gas properties as
additional collateral. We do not anticipate having any
substantial unpledged properties, and we may not have the
financial resources in the future to make any mandatory
principal prepayments required under our new revolving credit
facility. Additionally, we anticipate that if, at the time of
any distribution, our borrowings equal or exceed the maximum
percentage allowed of the then-specified borrowing base, we will
not be able to pay distributions to our unitholders in any such
quarter without first making the required repayments of
indebtedness under our new revolving credit facility.
Our
operations are subject to operational hazards and unforeseen
interruptions for which we may not be adequately
insured.
There are a variety of operating risks inherent in our wells and
other operating properties and facilities, such as leaks,
explosions, mechanical problems and natural disasters, all of
which could cause substantial financial losses. Any of these or
other similar occurrences could result in the disruption of our
operations, substantial repair costs, personal injury or loss of
human life, significant damage to property, environmental
pollution, impairment of our operations and substantial revenue
losses. The location of our wells and other operating properties
and facilities near populated areas, including residential
areas, commercial business centers and industrial sites, could
significantly increase the level of damages resulting from these
risks.
34
Insurance against all operational risk is not available to us.
We are not fully insured against all risks, including
development and completion risks that are generally not
recoverable from third parties or insurance. In addition,
pollution and environmental risks generally are not fully
insurable. Additionally, we may elect not to obtain insurance if
we believe that the cost of available insurance is excessive
relative to the perceived risks presented. Losses could,
therefore, occur for uninsurable or uninsured risks or in
amounts in excess of existing insurance coverage. Moreover,
insurance may not be available in the future at commercially
reasonable costs and on commercially reasonable terms. Changes
in the insurance markets due to weather, adverse economic
conditions, and the aftermath of the Macondo well incident in
the Gulf of Mexico have made it more difficult for us to obtain
certain types of coverage. As a result, we may not be able to
obtain the levels or types of insurance we would otherwise have
obtained prior to these market changes, and we cannot be sure
the insurance coverage we do obtain will contain large
deductibles or fail to cover certain hazards or cover all
potential losses. Losses and liabilities from uninsured and
underinsured events and delay in the payment of insurance
proceeds could have a material adverse effect on our business,
financial condition, results of operations and ability to make
distributions to our unitholders.
Our
business depends in part on pipelines, gathering systems and
processing facilities owned by others. Any limitation in the
availability of those facilities could interfere with our
ability to market our oil and natural gas production and could
harm our business.
The marketability of our oil and natural gas production depends
in part on the availability, proximity and capacity of pipelines
and other transportation methods, gathering systems and
processing facilities owned by third parties. The amount of oil
and natural gas that can be produced and sold is subject to
curtailment in certain circumstances, such as pipeline
interruptions due to scheduled and unscheduled maintenance,
excessive pressure, physical damage or lack of contracted
capacity on such systems. Our access to transportation options
can also be affected by U.S. federal and state regulation
of oil and natural gas production and transportation, general
economic conditions and changes in supply and demand. The
curtailments arising from these and similar circumstances may
last from a few days to several months. In many cases, we are
provided only with limited, if any, notice as to when these
circumstances will arise and their duration. Any significant
curtailment in gathering system or transportation or processing
facility capacity could reduce our ability to market our oil and
natural gas production and harm our business.
The
operation of our properties is largely dependent on the ability
of Memorial Resources employees.
The continuing production from a property, and to some extent
the marketing of production, is dependent upon the ability of
the operators of our properties. Memorial Resource will operate
substantially all of the Partnership Properties, either directly
as operator or, where we are the operator of record, on our
behalf. As of December 31, 2010, we operate 41%, Memorial
Resource operates 53% and third parties operate 6% of the wells
and properties in which we have interests. As a result, the
success and timing of drilling and development activities on
such properties, depend upon a number of factors, including:
|
|
|
|
|
the nature and timing of drilling and operational activities;
|
|
|
|
the timing and amount of capital expenditures;
|
|
|
|
Memorial Resources or the operators expertise and
financial resources;
|
|
|
|
the approval of other participants in such properties; and
|
|
|
|
the selection and application of suitable technology.
|
If Memorial Resource or the applicable third party operator is
unable to conduct drilling and development activities on our
properties on a timely basis, we may be unable to increase our
production or offset normal production declines, or we will be
required to write off the estimated proved reserves attributable
thereto, any of which may adversely affect our production,
revenues and results of operations and our cash available for
distribution. Any such write-offs of our reserves could reduce
our ability to borrow money and could adversely impact our
ability to pay distributions on the common units.
35
Where we are operator of the wells located on our properties,
our operations will be generally governed by operating
agreements if any third party has interests in these properties,
which agreements typically require the operator to conduct
operations in a good and workmanlike manner. For the wells
located on our properties that Memorial Resource or a third
party is the operator, the operator will generally not be a
fiduciary with respect to us or our unitholders. As an owner of
working interests in properties not operated by us, we will
generally have a cause of action for damages arising from a
breach of the operators duty.
Our
historical and pro forma financial information may not be
representative of our future performance.
The historical financial information included in this prospectus
is derived from our predecessors historical financial
statements for periods prior to our initial public offering. Our
predecessors historical financial statements were prepared
in accordance with GAAP and reflect certain assets and
operations that will not be included in our partnership and
exclude certain assets and operations that will be included in
our partnership. Accordingly, the historical financial
information included in this prospectus does not reflect what
our results of operations and financial condition would have
been had we been a public entity during the periods presented,
or what our results of operations and financial condition will
be in the future.
In preparing the unaudited pro forma financial information
included in this prospectus, we have made adjustments to our
predecessors historical financial information based upon
currently available information and upon assumptions that our
management believes are reasonable in order to reflect, on a pro
forma basis, the impact of the items discussed in our unaudited
pro forma financial statements and related notes. The estimates
and assumptions used in the calculation of the pro forma
financial information in this prospectus may be materially
different from our actual experience as a public entity.
Accordingly, the pro forma financial information included in
this prospectus does not purport to represent what our results
of operations would actually have been had the transactions that
are reflected in our unaudited pro forma financial statements
actually taken place, nor does it represent what our results of
operations would have been had we operated as a public entity
during the periods presented. The pro forma financial
information also does not purport to represent what our results
of operations and financial condition will be in the future, nor
does the unaudited pro forma financial information give effect
to any events other than those discussed in our unaudited pro
forma financial statements and related notes.
We are
subject to complex federal, state, local and other laws and
regulations that could adversely affect the cost, manner or
feasibility of conducting our operations.
Our oil and natural gas development and production operations
are subject to complex and stringent laws and regulations. To
conduct our operations in compliance with these laws and
regulations, we must obtain and maintain numerous permits,
approvals and certificates from various federal, state and local
governmental authorities. We may incur substantial costs in
order to maintain compliance with these existing laws and
regulations. In addition, our costs of compliance may increase
if existing laws and regulations are revised or reinterpreted,
or if new laws and regulations become applicable to our
operations.
Our business is subject to federal, state and local laws and
regulations as interpreted and enforced by governmental
authorities possessing jurisdiction over various aspects of the
exploration for, and production and processing of, oil and
natural gas. Failure to comply with such laws and regulations,
as interpreted and enforced, could have a material adverse
effect on our business, financial condition, results of
operations and ability to make distributions to our unitholders.
Please read Business and Properties
Environmental Matters and Regulation and Business
and Properties Other Regulation of the Oil and
Natural Gas Industry for a description of the laws and
regulations that affect us.
Climate
change legislation or regulations restricting emissions of
greenhouse gases could result in increased operating
costs and reduced demand for the oil and natural gas that we
produce.
On April 2, 2007, the U.S. Supreme Court ruled, in
Massachusetts, et al. v. EPA, that the federal Clean Air
Act definition of pollutant includes carbon dioxide
and other greenhouse gases, or GHGs, and, therefore, the
U.S. Environmental Protection Agency, or EPA, has the
authority to regulate carbon dioxide emissions
36
from automobiles. Thereafter, on December 15, 2009, the EPA
published its findings that emissions of carbon dioxide, or
CO2,
methane, and other GHGs present an endangerment to public health
and the environment because emissions of such gases are,
according to the EPA, contributing to the warming of the
earths atmosphere and other climate changes. These
findings allowed the EPA to adopt and implement regulations that
would restrict emissions of GHGs under existing provisions of
the federal Clean Air Act. The EPA subsequently adopted two sets
of regulations under the existing Clean Air Act that would
require a reduction in emissions of GHGs from motor vehicles and
certain stationary sources to obtain permits and employ
technologies to reduce GHG emissions. The EPA published the
motor vehicle final rule in May 2010 and it became effective
January 2011 and applies to vehicles manufactured in model years
2012-2016.
The EPA adopted the stationary source rule in May 2010, and it
also became effective January 2011, applying first to the
largest emitters of GHGs and providing the potential for
application to smaller emitters in later years. Both rules
remain the subject of several lawsuits filed by industry groups
in the U.S. Court of Appeals for the District of Columbia
Circuit. Additionally, the EPA requires reporting of GHG
emissions from certain emission sources. In October 2009, the
EPA published a final rule requiring the reporting of GHG
emissions from specified large GHG emission sources in the U.S.,
including natural gas liquids fractionators and local natural
gas/distribution companies, beginning in 2011 for emissions
occurring in 2010. Furthermore, in November 2010, the EPA
expanded its existing GHG reporting rule to include onshore oil
and natural gas production, processing, transmission, storage,
and distribution facilities. The final rule, which may be
applicable to many of our facilities, will require reporting of
GHG emissions from such facilities on an annual basis, with
reporting beginning in 2012 for emissions occurring in 2011. In
June 2009, the U.S. House of Representatives passed the
American Clean Energy and Security (ACES) Act that, among other
things, would have established a
cap-and-trade
system to regulate greenhouse gas emissions and would have
required an 80% reduction in GHG emissions from sources within
the United States between 2012 and 2050. The ACES Act did not
pass the Senate, however, and so was not enacted by the
111th Congress. The United States Congress is likely to
consider again a climate change bill in the future. In addition,
almost one-half of the states have already taken legal measures
to reduce emissions of GHGs, primarily through the planned
development of GHG emission inventories
and/or
regional GHG cap and trade programs. Most of these cap and trade
programs work by requiring either major sources of emissions or
major producers of fuels to acquire and surrender emission
allowances, with the number of allowances available for purchase
reduced each year until the overall GHG emission reduction goal
is achieved. The adoption of any legislation or regulations that
requires reporting of GHGs or otherwise limits emissions of GHGs
from our equipment and operations could require us to incur
costs to monitor and report on GHG emissions or reduce emissions
of GHGs associated with our operations, and such requirements
also could adversely affect demand for the oil and natural gas
that we produce. Please read Business and
Properties Environmental Matters and
Regulation.
Our
operations are subject to environmental and operational safety
laws and regulations that may expose us to significant costs and
liabilities.
Our oil and natural gas development and production operations
are subject to stringent and complex federal, state and local
laws and regulations governing the discharge of materials into
the environment, health and safety aspects of our operations, or
otherwise relating to environmental protection. These laws and
regulations may impose numerous obligations applicable to our
operations including the acquisition of a permit before
conducting regulated drilling activities; the restriction of
types, quantities and concentration of materials that can be
released into the environment; the limitation or prohibition of
drilling activities on certain lands lying within wilderness,
wetlands and other protected areas; the application of specific
health and safety criteria addressing worker protection; and the
imposition of substantial liabilities for pollution resulting
from our operations. Numerous governmental authorities, such as
the EPA, and analogous state agencies have the power to enforce
compliance with these laws and regulations and the permits
issued under them, often requiring difficult and costly
compliance or corrective actions. Failure to comply with these
laws and regulations may result in the assessment of sanctions,
including administrative, civil or criminal penalties, the
imposition of investigatory or remedial obligations, and the
issuance of orders limiting or prohibiting some or all of our
operations. In addition, we may experience delays in obtaining
or be unable to obtain required permits, which may delay or
interrupt our operations and limit our growth and revenue.
37
There is inherent risk of incurring significant environmental
costs and liabilities in the performance of our operations due
to our handling of petroleum hydrocarbons and wastes, because of
air emissions and wastewater discharges related to our
operations, and as a result of historical industry operations
and waste disposal practices. Under certain environmental laws
and regulations, we could be subject to joint and several strict
liability for the removal or remediation of previously released
materials or property contamination regardless of whether we
were responsible for the release or contamination or if the
operations were in compliance with all applicable laws at the
time those actions were taken. Private parties, including the
owners of properties upon which our wells are drilled and
facilities where our petroleum hydrocarbons or wastes are taken
for reclamation or disposal, also may have the right to pursue
legal actions to enforce compliance as well as to seek damages
for non-compliance with environmental laws and regulations or
for personal injury or property or natural resource damages. In
addition, the risk of accidental spills or releases could expose
us to significant liabilities that could have a material adverse
effect on our business, financial condition or results of
operations. Changes in environmental laws and regulations occur
frequently, and any changes that result in more stringent or
costly waste control, handling, storage, transport, disposal or
cleanup requirements could require us to make significant
expenditures to attain and maintain compliance and may otherwise
have a material adverse effect on our own results of operations,
competitive position or financial condition. We may not be able
to recover some or any of these costs from insurance. Please
read Business and Properties Environmental
Matters and Regulation for more information.
The
third parties on whom we rely for gathering and transportation
services are subject to complex federal, state and other laws
that could adversely affect the cost, manner or feasibility of
conducting our business.
The operations of the third parties on whom we rely for
gathering and transportation services are subject to complex and
stringent laws and regulations that require obtaining and
maintaining numerous permits, approvals and certifications from
various federal, state and local government authorities. These
third parties may incur substantial costs in order to comply
with existing laws and regulations. If existing laws and
regulations governing such third-party services are revised or
reinterpreted, or if new laws and regulations become applicable
to their operations, these changes may affect the costs that we
pay for such services. Similarly, a failure to comply with such
laws and regulations by the third parties on whom we rely could
have a material adverse effect on our business, financial
condition, results of operations and ability to make
distributions to our unitholders. Please read Business and
Properties Environmental Matters and
Regulation and Business and Properties
Other Regulation of the Oil and Natural Gas Industry for a
description of the laws and regulations that affect the third
parties on whom we rely.
The
recent adoption of derivatives legislation by the U.S. Congress
could have an adverse effect on our ability to use derivative
contracts to reduce the effect of commodity price, interest rate
and other risks associated with our business.
The U.S. Congress recently adopted comprehensive financial
reform legislation that establishes federal oversight and
regulation of the
over-the-counter
derivatives market and entities that participate in that market.
The Commodity Futures Trading Commission, or the CFTC, has also
proposed regulations to set position limits for certain futures
and option contracts in the major energy markets, although it is
not possible at this time to predict whether or when the CFTC
will adopt those rules or include comparable provisions in its
rulemaking under the new legislation. The financial reform
legislation may require us to comply with margin requirements
and with certain clearing and trade-execution requirements,
although the application of those provisions to us is uncertain
at this time. The financial reform legislation may also require
the counterparties to our derivative contracts to spin off some
of their derivatives contracts to a separate entity, which may
not be as creditworthy as the current counterparty. The new
legislation and any new regulations could significantly increase
the cost of derivative contracts (including through requirements
to post collateral), materially alter the terms of derivative
contracts, reduce the availability of derivatives to protect
against risks we encounter, reduce our ability to monetize or
restructure our existing derivative contracts, and increase our
exposure to less creditworthy counterparties. If we reduce our
use of derivatives as a result of the legislation and
regulations, our results of operations may become more volatile
and our cash flows may be less predictable, which could
38
adversely affect our ability to plan for and fund capital
expenditures and fund unitholder distributions. Finally, the
legislation was intended, in part, to reduce the volatility of
oil and natural gas prices, which some legislators attributed to
speculative trading in derivatives and commodity contracts
related to oil and natural gas. Our revenues could therefore be
adversely affected if a consequence of the legislation and
regulations is to lower commodity prices. Any of these
consequences could have a material adverse effect on us, our
financial condition, and our results of operations.
Federal
and state legislative and regulatory initiatives relating to
hydraulic fracturing could result in increased costs and
additional operating restrictions or delays.
Hydraulic fracturing is a process used by oil and natural gas
exploration and production operators in the completion of
certain oil and natural gas wells whereby water, sand and
chemicals are injected under pressure into subsurface formations
to stimulate natural gas and, to a lesser extent, oil
production. This process is typically regulated by state oil and
natural gas agencies and has not been subject to federal
regulation. However, due to concerns that hydraulic fracturing
may adversely affect drinking water supplies, the EPA has
commenced a study of the potential adverse effects that
hydraulic fracturing may have on water quality and public
health, and a committee of the U.S. House of
Representatives has commenced its own investigation into
hydraulic fracturing practices. Additionally, legislation has
been introduced in the U.S. Congress to amend the federal
Safe Drinking Water Act to subject hydraulic fracturing
processes to regulation under that Act and to require the
disclosure of chemicals used by the oil and natural gas industry
in the hydraulic fracturing process. If enacted, such a
provision could require hydraulic fracturing activities to meet
permitting and financial assurance requirements, adhere to
certain construction specifications, fulfill monitoring,
reporting and recordkeeping requirements and meet plugging and
abandonment requirements.
In unrelated oil spill legislation being considered by the
U.S. Senate in the aftermath of the April 2010 Macondo well
release in the Gulf of Mexico, Senate Majority Leader Harry Reid
has added a requirement that natural gas drillers disclose the
chemicals they pump into the ground as part of the hydraulic
fracturing process. Disclosure of chemicals used in the
fracturing process could make it easier for third parties
opposing hydraulic fracturing to initiate legal proceedings
based on allegations that specific chemicals used in the
fracturing process could adversely affect groundwater. Adoption
of legislation or of any implementing regulations placing
restrictions on hydraulic fracturing activities could impose
operational delays, increased operating costs and additional
regulatory burdens on our exploration and production activities,
which could make it more difficult to perform hydraulic
fracturing, resulting in reduced amounts of oil and natural gas
being produced, as well as increase our costs of compliance and
doing business.
Increases
in interest rates could adversely impact our unit price and our
ability to issue additional equity and incur debt.
Interest rates on future credit facilities and debt offerings
could be higher than current levels, causing our financing costs
to increase accordingly. Also, as with other yield-oriented
securities, our unit price is impacted by the level of our cash
distributions to our unitholders and the implied distribution
yield. The distribution yield is often used by investors to
compare and rank similar yield-oriented securities for
investment decision-making purposes. Therefore, changes in
interest rates, either positive or negative, may affect the
yield requirements of investors who invest in our common units,
and a rising interest rate environment could have an adverse
impact on our unit price, our ability to issue additional equity
or incur debt, and the cost to us of any such issuance or
incurrence.
Risks
Inherent in an Investment in Us
Our
general partner and its affiliates own a controlling interest in
us and will have conflicts of interest with, and owe limited
fiduciary duties to, us, which may permit them to favor their
own interests to the detriment of our unitholders.
Our general partner will have control over all decisions related
to our operations. Upon consummation of this offering, Memorial
Resource will control an
aggregate % of our outstanding
common units and all of
39
our subordinated units, and 100% of the voting membership
interests in our general partner will be owned by Memorial
Resource. The Funds, in turn, collectively own 100% of Memorial
Resource. The directors and officers of our general partner have
a fiduciary duty to manage our general partner in a manner
beneficial to the owners of our general partner. However,
certain directors and officers of our general partner are
directors
and/or
officers of affiliates of our general partner (including
Memorial Resource, the Funds and NGP), and certain of our
general partners executive officers and directors will
continue to have economic interests, investments and other
economic incentives in the Funds and other NGP-affiliated
entities. Conflicts of interest may arise in the future between
our general partner and its affiliates (including Memorial
Resource, the Funds and NGP), on the one hand, and us and our
unitholders, on the other hand. In resolving these conflicts,
our general partner may favor its own interests and the
interests of its affiliates over the interests of our
unitholders and us. Please read Our
partnership agreement limits our general partners
fiduciary duties to unitholders and restricts the remedies
available to unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty. These potential conflicts include, among others, the
following situations:
|
|
|
|
|
neither our partnership agreement nor any other agreement
requires Memorial Resource, the Funds or NGP to pursue a
business strategy that favors us. The directors and officers of
Memorial Resource, the Funds and their respective affiliates
(including NGP) have a fiduciary duty to make decisions in the
best interests of their respective equity holders, which may be
contrary to our interests;
|
|
|
|
our general partner is allowed to take into account the
interests of parties other than us, such as its owner, in
resolving conflicts of interest, which has the effect of
limiting its fiduciary duty to our unitholders;
|
|
|
|
Memorial Resource, the Funds and their affiliates (including
NGP) are not limited in their ability to compete with us,
including with respect to future acquisition opportunities, and
are under no obligation to offer assets to us. Please read
Conflicts of Interest and Fiduciary Duties
Conflicts of Interest Memorial Resource, the Funds
and other affiliates of our general partner will not be limited
in their ability to compete with us, which could cause conflicts
of interest and limit our ability to acquire additional assets
or businesses;
|
|
|
|
except in limited circumstances, our general partner has the
power and authority to conduct our business without unitholder
approval;
|
|
|
|
many of the officers and directors of our general partner who
will provide services to us will devote time to affiliates of
our general partner, including Memorial Resource, the Funds,
and/or NGP,
and may be compensated for services rendered to such affiliates;
|
|
|
|
our general partner has limited its liability and reduced its
fiduciary duties, and has also restricted the remedies available
to our unitholders for actions that, without such limitations,
reductions, and restrictions, might constitute breaches of
fiduciary duty. By purchasing common units, unitholders are
consenting to some actions and conflicts of interest that might
otherwise constitute a breach of fiduciary or other duties under
applicable law;
|
|
|
|
our general partner determines the amount and timing of our
drilling program and related capital expenditures, asset
purchases and sales, borrowings, issuance of additional
partnership interests, other investments, including investment
capital expenditures in other partnerships with which our
general partner is or may become affiliated, and the creation,
reduction or increase of cash reserves, each of which can affect
the amount of cash that is distributed to unitholders;
|
|
|
|
our general partner determines whether a cash expenditure is
classified as a growth capital expenditure, which does not
reduce operating surplus. This determination can affect the
amount of cash that is distributed to our unitholders and to our
general partner, the amount of adjusted operating surplus in any
given period and the ability of the subordinated units to
convert into common units;
|
|
|
|
we and our general partner will enter into an omnibus agreement
with Memorial Resource in connection with this offering,
pursuant to which, among other things, Memorial Resource will
operate
|
40
|
|
|
|
|
our assets and perform other management, administrative, and
operating services for us and our general partner;
|
|
|
|
|
|
our general partner is entitled to determine which costs,
including allocated overhead, incurred by it and its affiliates,
including Memorial Resource, are reimbursable by us, which will
include salary, bonus, incentive compensation and other amounts
paid to persons who perform services for us or on our behalf,
and expenses allocated to our general partner by its affiliates;
|
|
|
|
our general partner may cause us to borrow funds in order to
permit the payment of cash distributions, even if the purpose or
effect of the borrowing is to make a distribution on the
subordinated units, to make incentive distributions or to
accelerate the expiration of the subordination period;
|
|
|
|
our partnership agreement permits us to classify up to
$ million as operating
surplus, even if it is generated from asset sales, non-working
capital borrowings or other sources that would otherwise
constitute capital surplus. This cash may be used to fund
distributions on our subordinated units or to our general
partner in respect of the general partner interest or the
incentive distribution rights;
|
|
|
|
our general partner decides whether to retain separate counsel,
accountants, or others to perform services for us;
|
|
|
|
our general partner may elect to cause us to issue common units
to it in connection with a resetting of the target distribution
levels related to our general partners incentive
distribution rights without the approval of the conflicts
committee of the board of directors of our general partner or
our unitholders. This election may result in lower distributions
to our common unitholders in certain situations;
|
|
|
|
our partnership agreement does not restrict our general partner
from causing us to pay it or its affiliates for any services
rendered to us or entering into additional contractual
arrangements with any of these entities on our behalf;
|
|
|
|
our general partner intends to limit its liability regarding our
contractual and other obligations and, in some circumstances, is
entitled to be indemnified by us;
|
|
|
|
our general partner may exercise its limited right to call and
purchase common units if it and its affiliates own more than 80%
of the common units;
|
|
|
|
our general partner controls the enforcement of obligations owed
to us by our general partner and its affiliates, including
Memorial Resource, the Funds and NGP; and
|
|
|
|
our general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
|
Please read Certain Relationships and Related Party
Transactions and Conflicts of Interest and Fiduciary
Duties.
Memorial
Resource, the Funds and other affiliates of our general partner
will not be limited in their ability to compete with us, which
could cause conflicts of interest and limit our ability to
acquire additional assets or businesses.
Our partnership agreement provides that Memorial Resource and
the Funds and their respective affiliates (including NGP and its
affiliates portfolio investments) are not restricted from
owning assets or engaging in businesses that compete directly or
indirectly with us. In addition, Memorial Resource and the Funds
and their respective affiliates may acquire, develop or dispose
of additional oil and natural gas properties or other assets in
the future, without any obligation to offer us the opportunity
to purchase or develop any of those assets.
NGP and the Funds are established participants in the oil and
natural gas industry, and have resources greater than ours,
which factors may make it more difficult for us to compete with
them with respect to commercial activities as well as for
potential acquisitions. As a result, competition from these
affiliates could adversely impact our results of operations and
cash available for distribution to our unitholders. Please read
Conflicts of Interest and Fiduciary Duties.
41
Neither
we nor our general partner have any employees and we will rely
solely on the employees of Memorial Resource to manage our
business. The management team of Memorial Resource, which
includes the individuals who will manage us, will also perform
substantially similar services for itself and will own and
operate its own assets, and thus will not be solely focused on
our business.
Neither we nor our general partner have any employees and we
will rely solely on Memorial Resource to operate our assets.
Upon consummation of this offering, we and our general partner
will enter into an omnibus agreement with Memorial Resource,
pursuant to which, among other things, Memorial Resource will
agree to operate our assets and perform other management,
administrative, and operating services for us and our general
partner.
Memorial Resource will provide substantially similar activities
with respect to its own assets and operations. Because Memorial
Resource will be providing services to us that are substantially
similar to those performed for itself, Memorial Resource may not
have sufficient human, technical and other resources to provide
those services at a level that Memorial Resource would be able
to provide to us if it were solely focused on our business and
operations. Memorial Resource may make internal decisions on how
to allocate its available resources and expertise that may not
always be in our best interest compared to Memorial
Resources interests. There is no requirement that Memorial
Resource favor us over itself in providing its services. If the
employees of Memorial Resource and their affiliates do not
devote sufficient attention to the management and operation of
our business, our financial results may suffer and our ability
to make distributions to our unitholders may be reduced.
Our
predecessor has material weaknesses in its internal control over
financial reporting. If we fail to establish and maintain
effective internal control over financial reporting, our ability
to accurately report our financial results could be adversely
affected.
Prior to the completion of this offering, our predecessor has
been a private entity with limited accounting personnel and
other supervisory resources to adequately execute its accounting
processes and address its internal control over financial
reporting. In connection with our predecessors audit for
the year ended December 31, 2010, our predecessors
independent registered accounting firm identified and
communicated material weaknesses related to lack of accounting
personnel with sufficient technical accounting experience for
certain significant or unusual transactions and lack of
management review at the appropriate level for certain
non-routine areas. A material weakness is a
deficiency, or combination of deficiencies, in internal controls
such that there is a reasonable possibility that a material
misstatement of our predecessors financial statements will
not be prevented, or detected in a timely basis. The lack of
technical accounting experience and management review resulted
in several audit adjustments to the financial statements for the
year ended December 31, 2010, 2009, and 2008.
After the closing of this offering, our management team and
financial reporting oversight personnel will be those of
Memorial Resource and our predecessor, and thus, we may face the
same material weaknesses described above.
Prior to the completion of our predecessors audit for the
year ended December 31, 2010, Memorial Resource and our
predecessors management began to implement new accounting
processes and control procedures and also hired additional
personnel.
While we have begun the process of evaluating the design and
operation of our internal control over financial reporting, we
are in the early phases of our review and will not complete our
review until after this offering is completed. We cannot predict
the outcome of our review at this time. During the course of the
review, we may identify additional control deficiencies, which
could give rise to significant deficiencies and other material
weaknesses, in addition to the material weaknesses described
above. Each of the material weaknesses described above could
result in a misstatement of our accounts or disclosures that
would result in a material misstatement of our annual or interim
combined financial statements that would not be prevented or
detected. We cannot assure you that the measures we have taken
to date, or any measures we may take in the future, will be
sufficient to remediate the material weaknesses described above
or avoid potential future material weaknesses.
42
We are not currently required to comply with the SECs
rules implementing Section 404 of the Sarbanes Oxley Act of
2002, and are therefore not required to make a formal assessment
of the effectiveness of our internal control over financial
reporting for that purpose. Upon becoming a publicly traded
partnership, we will be required to comply with the SECs
rules implementing Sections 302 and 404 of the Sarbanes
Oxley Act of 2002, which will require our management to certify
financial and other information in our quarterly and annual
reports and provide an annual management report on the
effectiveness of our internal control over financial reporting.
Though we will be required to disclose changes made to our
internal controls and procedures on a quarterly basis, we will
not be required to make our first annual assessment of our
internal control over financial reporting pursuant to
Section 404 until the year following our first annual
report required to be filed with the SEC. To comply with the
requirements of being a publicly traded partnership, we will
need to implement additional internal controls, reporting
systems and procedures and hire additional accounting, finance
and legal staff.
Further, our independent registered public accounting firm is
not yet required to formally attest to the effectiveness of our
internal controls over financial reporting until the year
following our first annual report required to be filed with the
SEC. If it is required to do so, our independent registered
public accounting firm may issue a report that is adverse in the
event it is not satisfied with the level at which our controls
are documented, designed or operating. Our remediation efforts
may not enable us to remedy or avoid material weaknesses or
significant deficiencies in the future.
If we
fail to develop or maintain an effective system of internal
controls, we may not be able to accurately report our financial
results or prevent fraud. As a result, current and potential
unitholders could lose confidence in our financial reporting,
which would harm our business and the trading price of our
units.
Effective internal controls are necessary for us to provide
reliable financial reports, prevent fraud and operate
successfully as a public company. If we cannot provide reliable
financial reports or prevent fraud, our reputation and operating
results would be harmed. We cannot be certain that our efforts
to develop and maintain our internal controls will be
successful, that we will be able to maintain adequate controls
over our financial processes and reporting in the future or that
we will be able to comply with our obligations under
Section 404 of the Sarbanes Oxley Act of 2002. Any failure
to develop or maintain effective internal controls, or
difficulties encountered in implementing or improving our
internal controls, could harm our operating results or cause us
to fail to meet our reporting obligations. Ineffective internal
controls could also cause investors to lose confidence in our
reported financial information, which would likely have a
negative effect on the trading price of our units.
Many
of the directors and all of the officers who have responsibility
for our management have significant duties with, and will spend
significant time serving, entities that compete with us in
seeking acquisitions and business opportunities and,
accordingly, may have conflicts of interest in allocating time
or pursuing business opportunities.
All of the officers of our general partner hold similar
positions with Memorial Resource, and many of the directors of
our general partner, who are responsible for managing our
general partners direction of our operations and
acquisition activities, hold positions of responsibility with
other entities (including NGP-affiliated entities) that are in
the business of identifying and acquiring oil and natural gas
properties. For example, the Funds and their affiliates
(including NGP) are in the business of investing in oil and
natural gas companies with independent management teams that
also seek to acquire oil and natural gas properties, and
Memorial Resource is in the business of acquiring and developing
oil and natural gas properties. Mr. Hersh, a director of
our general partner, is the Chief Executive Officer of NGP
Energy Capital Management and a managing partner of NGP; and
Mr. Weinzierl, the President, Chief Executive Officer and
Chairman of the board of directors of our general partner, was a
managing director of NGP prior to assuming his current positions
with Memorial Resource and our general partner and continues to
hold ownership interests in the Funds and certain of their
affiliates. After the closing of this offering, officers of our
general partner will continue to devote significant time to the
business of Memorial Resource. We cannot assure you that any
43
conflicts that may arise between us and our unitholders, on the
one hand, and Memorial Resource or the Funds, on the other hand,
will be resolved in our favor. The existing positions held by
these directors and officers may give rise to fiduciary duties
that are in conflict with the fiduciary duties they owe to us.
These officers and directors may become aware of business
opportunities that may be appropriate for presentation to us as
well as to the other entities with which they are or may become
affiliated. Due to these existing and potential future
affiliations, they may present potential business opportunities
to other entities prior to presenting them to us, which could
cause additional conflicts of interest. They may also decide
that certain opportunities are more appropriate for other
entities with which they are affiliated, and as a result, they
may elect not to present them to us. For additional discussion
of our managements business affiliations and the potential
conflicts of interest of which our unitholders should be aware,
please read Business and Properties Our
Principal Business Relationships and Conflicts of
Interest and Fiduciary Duties.
Cost
reimbursements due to Memorial Resource and our general partner
for services provided to us or on our behalf will be substantial
and will reduce our cash available for distribution to our
unitholders. The amount and timing of such reimbursements will
be determined by our general partner.
Our partnership agreement requires us to reimburse our general
partner and its affiliates for all actual direct and indirect
expenses they incur or actual payments they make on our behalf
and all other expenses allocable to us or otherwise incurred by
our general partner or its affiliates in connection with
operating our business, including overhead allocated to our
general partner by its affiliates, including Memorial Resource.
These expenses include salary, bonus, incentive compensation
(including equity compensation) and other amounts paid to
persons who perform services for us or on our behalf, and
expenses allocated to our general partner by its affiliates. Our
general partner is entitled to determine in good faith the
expenses that are allocable to us.
Prior to making distributions on our common units, we will
reimburse our general partner and its affiliates for all such
expenses. None of these reimbursements are capped. The
reimbursements to Memorial Resource and our general partner will
reduce the amount of cash otherwise available for distribution
to our unitholders.
At the closing of this offering, we will enter into agreements
with Memorial Resource and our general partner pursuant to
which, among other things, we will make payments to Memorial
Resource. These payments will be substantial and will reduce the
amount of cash available for distribution to unitholders. These
include the following:
|
|
|
|
|
an omnibus agreement pursuant to which, among other things,
Memorial Resource will provide management, administrative and
operating services for us and our general partner; and
|
|
|
|
a tax sharing agreement pursuant to which we will pay Memorial
Resource (or its applicable affiliate(s)) our share of state and
local income and other taxes for which our results are included
in a combined or consolidated tax return filed by Memorial
Resource or its applicable affiliate(s). It is possible that
Memorial Resource or its applicable affiliate(s) may use its tax
attributes to cause its combined or consolidated group, of which
we may be a member for this purpose, to owe less or no tax. In
such a situation, we would pay Memorial Resource or its
applicable affiliate(s) the tax we would have owed had the tax
attributes not been available or used for our benefit, even
though Memorial Resource or its applicable affiliate(s) had no
cash tax expense for that period. Currently, the Texas Margin
tax (which has a maximum effective tax rate of 0.7% of federal
gross income apportioned to Texas) is the only tax that will be
included in a combined or consolidated tax return with Memorial
Resource or its applicable affiliate(s).
|
44
Our
general partner may elect to cause us to issue common units to
it in connection with a resetting of the target distribution
levels related to our general partners incentive
distribution rights without the approval of the conflicts
committee of the board of directors of our general partner or
our unitholders. This election may result in lower distributions
to our common unitholders in certain situations.
Our general partner has the right (but not the obligation), at
any time when there are no subordinated units outstanding and it
has received incentive distributions at the highest level to
which it is entitled (25%) for each of the prior four
consecutive fiscal quarters, to reset the initial target
distribution levels at higher levels based on our cash
distribution at the time of the exercise of the reset election.
Following any reset election by our general partner, the minimum
quarterly distribution will be reset to an amount equal to the
average cash contribution per common unit for the two fiscal
quarters immediately preceding the reset election (such amount
is referred to as the reset minimum quarterly
distribution) and the target distribution levels will be
reset to correspondingly higher levels based on percentage
increases above the reset minimum quarterly distribution.
If our general partner elects to reset the target distribution
levels, it will be entitled to receive a number of common units
and general partner units. The number of common units to be
issued to our general partner will be equal to that number of
common units which would have entitled their holder to an
average aggregate quarterly cash distribution in the prior two
quarters equal to the average of the distributions to our
general partner on the incentive distribution rights in the
prior two quarters. Our general partner will be issued the
number of general partner units necessary to maintain our
general partners interest in us that existed immediately
prior to the reset election. We anticipate that our general
partner would exercise this reset right (if at all) to
facilitate acquisitions or internal growth projects that would
not be sufficiently accretive to cash distributions per common
unit without such conversion; however, it is possible that our
general partner could exercise this reset election at a time
when it is experiencing, or expects to experience, declines in
the cash distributions it receives related to its incentive
distribution rights and may, therefore, desire to be issued
common units rather than retain the right to receive incentive
distributions based on the initial target distribution levels.
As a result, a reset election may cause our common unitholders
to experience a reduction in the amount of cash distributions
that our common unitholders would have otherwise received had we
not issued new common units and general partner units to our
general partner in connection with resetting the target
distribution levels. Please read Provisions of Our
Partnership Agreement Relating to Cash Distributions
General Partners Right to Reset Incentive Distribution
Levels.
Our
unitholders who fail to furnish certain information requested by
our general partner or who our general partner determines are
not eligible citizens may not be entitled to receive
distributions in kind upon our liquidation and their common
units will be subject to redemption.
We have the right to redeem all of the units of any holder that
is not an eligible citizen if we are or become subject to
federal, state, or local laws or regulations that, in the
reasonable determination of our general partner, create a
substantial risk of cancellation or forfeiture of any property
in which we have an interest because of the nationality,
citizenship or other related status of any limited partner. Our
general partner may require any limited partner or transferee to
furnish information about his nationality, citizenship or
related status. If a limited partner fails to furnish
information about his nationality, citizenship or other related
status within 30 days after a request for the information
or our general partner determines after receipt of the
information that the limited partner is not an eligible citizen,
the limited partner may be treated as a non-citizen assignee. A
non-citizen assignee does not have the right to direct the
voting of his units and may not receive distributions in kind
upon our liquidation. Furthermore, we have the right to redeem
all of the common units and subordinated units of any holder
that is not an eligible citizen or fails to furnish the
requested information. Please read The Partnership
Agreement Non-Citizen Assignees; Redemption.
Common
units held by persons who are non-taxpaying assignees will be
subject to the possibility of redemption.
If our general partner determines that our not being treated as
an association taxable as a corporation or otherwise taxable as
an entity for U.S. federal income tax purposes, coupled
with the tax status (or lack of
45
proof thereof) of one or more of our limited partners, has, or
is reasonably likely to have, a material adverse effect on our
ability to operate our assets or generate revenues from our
assets, then our general partner may adopt such amendments to
our partnership agreement as it determines are necessary or
advisable to obtain proof of the U.S. federal income tax
status of our limited partners (and their owners, to the extent
relevant) and permit us to redeem the units held by any person
whose tax status has or is reasonably likely to have a material
adverse effect on our ability to operate our assets or generate
revenues from our assets or who fails to comply with the
procedures instituted by our general partner to obtain proof of
the U.S. federal income tax status. Please read The
Partnership Agreement Non-Taxpaying Assignees;
Redemption.
Our
unitholders have limited voting rights and are not entitled to
elect our general partner or its board of directors. Memorial
Resource, as owner of our general partner, will have the power
to appoint and remove our general partners
directors.
Unlike the holders of common stock in a corporation, unitholders
have only limited voting rights on matters affecting our
business and, therefore, limited ability to influence
managements decisions regarding our business. Unitholders
will not elect our general partner or its board of directors on
an annual or other continuing basis. The board of directors of
our general partner will be appointed by Memorial Resource.
Furthermore, if the unitholders are dissatisfied with the
performance of our general partner, they will have little
ability to remove our general partner. As a result of these
limitations, the price at which the common units will trade
could be diminished because of the absence or reduction of a
takeover premium in the trading price.
Our general partner will have control over all decisions related
to our operations. Since, upon consummation of this offering,
Memorial Resource will own our general partner,
approximately % of our outstanding
common units, and all of our subordinated units, the other
unitholders will not have an ability to influence any operating
decisions and will not be able to prevent us from entering into
any transactions. Our partnership agreement generally may not be
amended during the subordination period without the approval of
our public common unitholders. However, our partnership
agreement can be amended with the consent of our general partner
and the approval of the holders of a majority of our outstanding
common units (including common units held by Memorial Resource
and its affiliates) after the subordination period has ended.
Assuming we do not issue any additional common units and
Memorial Resource does not transfer its common units, Memorial
Resource will have the ability to amend our partnership
agreement, including our policy to distribute all of our
available cash to our unitholders, without the approval of any
other unitholder once the subordination period ends.
Furthermore, the goals and objectives of Memorial Resource and
its affiliates that hold our common units relating to us may not
be consistent with those of a majority of the other unitholders.
Please read Our general partner and its
affiliates own a controlling interest in us and will have
conflicts of interest with, and owe limited fiduciary duties to,
us, which may permit them to favor their own interests to the
detriment of our unitholders.
Our
general partner will be required to deduct estimated maintenance
capital expenditures from our operating surplus, which may
result in less cash available for distribution to unitholders
from operating surplus than if actual maintenance capital
expenditures were deducted.
Maintenance capital expenditures are those capital expenditures
required to maintain our long-term asset base, including
expenditures to replace our oil and natural gas reserves
(including non-proved reserves attributable to undeveloped
leasehold acreage), whether through the development,
exploitation and production of an existing leasehold or the
acquisition or development of a new oil or natural gas property.
Our partnership agreement requires our general partner to deduct
estimated, rather than actual, maintenance capital expenditures
from operating surplus in determining cash available for
distribution from operating surplus. The amount of estimated
maintenance capital expenditures deducted from operating surplus
will be subject to review and change by our conflicts committee
at least once a year. Our partnership agreement does not cap the
amount of maintenance capital expenditures that our general
partner may estimate. In years when our estimated maintenance
capital expenditures are higher than actual maintenance capital
expenditures, the amount of cash available for distribution to
unitholders from operating surplus will be lower than if actual
46
maintenance capital expenditures had been deducted from
operating surplus. On the other hand, if our general partner
underestimates the appropriate level of estimated maintenance
capital expenditures, we will have more cash available for
distribution from operating surplus in the short term but will
have less cash available for distribution from operating surplus
in future periods when we have to increase our estimated
maintenance capital expenditures to account for the previous
underestimation.
Our
partnership agreement limits our general partners
fiduciary duties to unitholders and restricts the remedies
available to unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
Our partnership agreement contains provisions that reduce the
fiduciary standards to which our general partner would otherwise
be held by state fiduciary duty laws. For example, our
partnership agreement:
|
|
|
|
|
permits our general partner to make a number of decisions in its
individual capacity, as opposed to in its capacity as our
general partner. This entitles our general partner to consider
only the interests and factors that it desires, and it has no
duty or obligation to give any consideration to any interest of,
or factors affecting, us, our affiliates or any limited partner.
Examples include the exercise of its limited call right, the
exercise of its rights to transfer or vote the units it owns,
the exercise of its registration rights and its determination
whether or not to consent to any merger or consolidation
involving us or to any amendment to the partnership agreement;
|
|
|
|
provides that our general partner will not have any liability to
us or our unitholders for decisions made in its capacity as
general partner so long as it acted in good faith;
|
|
|
|
generally provides that affiliated transactions and resolutions
of conflicts of interest not approved by the conflicts committee
of the board of directors of our general partner acting in good
faith and not involving a vote of unitholders must be on terms
no less favorable to us than those generally being provided to
or available from unrelated third parties or must be fair
and reasonable to us, as determined by our general partner
in good faith. In determining whether a transaction or
resolution is fair and reasonable, our general
partner may consider the totality of the relationships between
the parties involved, including other transactions that may be
particularly advantageous or beneficial to us;
|
|
|
|
provides that our general partner and its officers and directors
will not be liable for monetary damages to us or our limited
partners for any acts or omissions unless there has been a final
and non-appealable judgment entered by a court of competent
jurisdiction determining that our general partner or its
officers and directors acted in bad faith or engaged in fraud or
willful misconduct or, in the case of a criminal matter, acted
with knowledge that the conduct was criminal; and
|
|
|
|
provides that in resolving conflicts of interest, it will be
presumed that in making its decision our general partners
board of directors or the conflicts committee of our general
partners board of directors acted in good faith, and in
any proceeding brought by or on behalf of any limited partner or
us, the person bringing or prosecuting such proceeding will have
the burden of overcoming such presumption.
|
By purchasing a common unit, a unitholder will become bound by
the provisions in the partnership agreement, including the
provisions discussed above. Please read Conflicts of
Interest and Fiduciary Duties Fiduciary Duties.
Even
if our unitholders are dissatisfied, they cannot remove our
general partner without Memorial Resources
consent.
The public unitholders will be unable initially to remove our
general partner without Memorial Resources consent because
Memorial Resource will own sufficient units upon completion of
this offering to be able to prevent our general partners
removal. The vote of the holders of at least
662/3%
of all outstanding units voting together as a single class is
required to remove our general partner. Upon consummation of
this offering, Memorial Resource will own our general partner,
approximately % of our outstanding
common
47
units (approximately % if the
underwriters exercise their option to purchase additional common
units in full), and all of our subordinated units.
Control
of our general partner and its incentive distribution rights may
be transferred to a third party without unitholder
consent.
Our general partner may transfer its general partner interest to
a third party in a merger or in a sale of all or substantially
all of its assets without the consent of the unitholders.
Furthermore, our partnership agreement does not restrict the
ability of Memorial Resource from transferring all or a portion
of its ownership interest in our general partner to a third
party. The new owner of our general partner would then be in a
position to replace the board of directors and officers of our
general partner with their own choices and thereby influence the
decisions made by the board of directors and officers in a
manner that may not be aligned with the interests of our
unitholders.
In addition, our general partner may transfer its incentive
distribution rights to a third party at any time without the
consent of our unitholders. If our general partner transfers its
incentive distribution rights to a third party but retains its
general partner interest, our general partner may not have the
same incentive to grow our partnership and increase quarterly
distributions to unitholders over time as it would if it had
retained ownership of its incentive distribution rights.
We may
not make cash distributions during periods when we record net
income.
The amount of cash we have available for distribution to our
unitholders depends primarily on our cash flow, including cash
from reserves established by our general partner, working
capital or other borrowings, and not solely on profitability,
which will be affected by non-cash items. As a result, we may
make cash distributions to our unitholders during periods when
we record net losses and may not make cash distributions to our
unitholders during periods when we record net income.
We may
issue an unlimited number of additional units, including units
that are senior to the common units, without unitholder
approval, which would dilute unitholders ownership
interests.
Our partnership agreement does not limit the number of
additional common units that we may issue at any time without
the approval of our unitholders. In addition, we may issue an
unlimited number of units that are senior to the common units in
right of distribution, liquidation and voting. The issuance by
us of additional common units or other equity interests of equal
or senior rank will have the following effects:
|
|
|
|
|
our unitholders proportionate ownership interest in us
will decrease;
|
|
|
|
the amount of cash available for distribution on each unit may
decrease;
|
|
|
|
because a lower percentage of total outstanding units will be
subordinated units, the risk that a shortfall in the payment of
the minimum quarterly distribution will be borne by our common
unitholders will increase;
|
|
|
|
the ratio of taxable income to distributions may increase;
|
|
|
|
the relative voting strength of each previously outstanding unit
may be diminished; and
|
|
|
|
the market price of our common units may decline.
|
Our
partnership agreement restricts the limited voting rights of
unitholders, other than our general partner and its affiliates,
owning 20% or more of our common units, which may limit the
ability of significant unitholders to influence the manner or
direction of management.
Our partnership agreement restricts unitholders limited
voting rights by providing that any common units held by a
person, entity or group that owns 20% or more of any class of
common units then outstanding (other than our general partner,
its affiliates, their transferees and persons who acquired such
common units with the prior approval of the board of directors
of our general partner) cannot vote on any matter. Our
partnership
48
agreement also contains provisions limiting the ability of
unitholders to call meetings or to acquire information about our
operations, as well as other provisions limiting
unitholders ability to influence the manner or direction
of management.
Once
our common units are publicly traded, Memorial Resource may sell
common units in the public markets, which sales could have an
adverse impact on the trading price of the common
units.
After the sale of the common units offered hereby, Memorial
Resource will own an aggregate
of our outstanding common units and
all of our subordinated units, which convert into common units
at the end of the subordination period. Once our common units
are publicly traded, the sale of these units, including common
units issued upon the conversion of the subordinated units, in
the public markets could have an adverse impact on the price of
the common units or on any trading market that may develop.
Our
general partner has a call right that may require common
unitholders to sell their common units at an undesirable time or
price.
If at any time our general partner and its affiliates own more
than 80% of the common units, our general partner will have the
right, which it may assign to any of its affiliates or to us,
but not the obligation, to acquire all, but not less than all,
of the common units held by unaffiliated persons at a price that
is the greater of (i) the highest cash price paid by either
of our general partner or any of its affiliates for any common
units purchased within the 90 days preceding the date on
which our general partner first mails notice of its election to
purchase those common units; and (ii) the average daily
closing prices of our common units over the 20 days
preceding the date three days before the date the notice is
mailed. As a result, our unitholders may be required to sell
their common units at an undesirable time or price and may not
receive any return on their investment. Our unitholders also may
incur a tax liability upon a sale of their common units. Upon
consummation of this offering, Memorial Resource will own
approximately % of our outstanding
common units and all of our subordinated units. For additional
information about this call right, please read The
Partnership Agreement Limited Call Right.
If we
distribute cash from capital surplus, which is analogous to a
return of capital, our minimum quarterly distribution will be
reduced proportionately.
Our cash distributions will be characterized as coming from
either operating surplus or capital surplus. Operating surplus
is defined in our partnership agreement, and generally means
amounts we receive from operating sources, such as sale of our
oil and natural gas production, less operating expenditures,
such as production costs and taxes, and less estimated average
capital expenditures, which are generally amounts we estimate we
will need to spend in the future to maintain our production
levels over the long term. Capital surplus is defined in our
partnership agreement included in this prospectus as
Appendix A, and generally would result from cash received
from non-operating sources such as sales of properties and
issuances of debt and equity interests. Cash representing
capital surplus, therefore, is analogous to a return of capital.
Distributions of capital surplus are made to our unitholders and
our general partner in proportion to their percentage interests
in us, or 99.9% to our unitholders and 0.1% to our general
partner, and will result in a decrease in our minimum quarterly
distribution. For a more detailed description of operating
surplus, capital surplus and the effect of distributions from
capital surplus, please read Provisions of Our Partnership
Agreement Relating to Cash Distributions.
Our
unitholders liability may not be limited if a court finds
that unitholder action constitutes control of our
business.
A general partner of a partnership generally has unlimited
liability for the obligations of the partnership, except for
those contractual obligations of the partnership that are
expressly made without recourse to the general partner. Our
partnership is organized under Delaware law and we conduct
business in a number of other states. The limitations on the
liability of holders of limited partner interests for the
obligations of a
49
limited partnership have not been clearly established in some of
the other states in which we do business. A unitholder could be
liable for our obligations as if it was a general partner if:
|
|
|
|
|
a court or government agency determined that we were conducting
business in a state but had not complied with that particular
states partnership statute; or
|
|
|
|
a unitholders right to act with other unitholders to
remove or replace the general partner, to approve some
amendments to our partnership agreement or to take other actions
under our partnership agreement constitute control
of our business.
|
Please read The Partnership Agreement Limited
Liability for a discussion of the implications of the
limitations of liability on a unitholder.
Our
unitholders may have liability to repay
distributions.
Under certain circumstances, unitholders may have to repay
amounts wrongfully returned or distributed to them. Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, we may
not make distributions to unitholders if the distribution would
cause our liabilities to exceed the fair value of our assets.
Liabilities to partners on account of their partnership
interests and liabilities that are non-recourse to us are not
counted for purposes of determining whether a distribution is
permitted. Delaware law provides that for a period of three
years from the date of an impermissible distribution, limited
partners who received the distribution and who knew at the time
of the distribution that it violated Delaware law will be liable
to the limited partnership for the distribution amount. A
purchaser of common units who becomes a limited partner is
liable for the obligations of the transferring limited partner
to make contributions to us that are known to such purchaser of
common units at the time it became a limited partner and for
unknown obligations if the liabilities could be determined from
our partnership agreement.
Our
unitholders may have limited liquidity for their common units, a
trading market may not develop for the common units and our
unitholders may be unable to resell their common units at the
initial public offering price.
Prior to this offering, there has been no public market for the
common units. After this offering, there will be publicly traded
common units. We do not know the extent to which investor
interest will lead to the development of a trading market or how
liquid that market might be. Our unitholders may not be able to
resell their common units at or above the initial public
offering price. Additionally, a lack of liquidity would likely
result in wide bid-ask spreads, contribute to significant
fluctuations in the market price of the common units and limit
the number of investors who are able to buy the common units.
All of
the
common units that are issued to affiliates of our general
partner, or % of our outstanding
common units, will be subject to resale restrictions under a
180-day
lock-up
agreement with the underwriters. Each of the
lock-up
agreements with the underwriters may be waived in the discretion
of certain of the underwriters. Sales by affiliates of our
general partner of a substantial number of our common units in
the public markets following this offering, or the perception
that such sales might occur, could have a material adverse
effect on the price of our common units or could impair our
ability to obtain capital through an offering of equity
securities. In addition, we have agreed to provide registration
rights to our general partner and its affiliates. Under our
partnership agreement, our general partner and its affiliates
have registration rights relating to the offer and sale of any
units that they hold, subject to certain limitations.
If our
common unit price declines after the initial public offering,
our unitholders could lose a significant part of their
investment.
The initial public offering price for the common units will be
determined by negotiations between us and the representatives of
the underwriters and may not be indicative of the market price
of the common units that will prevail in the trading market. The
market price of our common units could be subject to wide
fluctuations in response to a number of factors, most of which
we cannot control, including:
|
|
|
|
|
changes in commodity prices;
|
50
|
|
|
|
|
changes in securities analysts recommendations and their
estimates of our financial performance;
|
|
|
|
public reaction to our press releases, announcements and filings
with the SEC;
|
|
|
|
fluctuations in broader securities market prices and volumes,
particularly among securities of oil and natural gas companies
and securities of publicly traded limited partnerships and
limited liability companies;
|
|
|
|
changes in market valuations of similar companies;
|
|
|
|
departures of key personnel;
|
|
|
|
commencement of or involvement in litigation;
|
|
|
|
variations in our quarterly results of operations or those of
other oil and natural gas companies;
|
|
|
|
variations in the amount of our quarterly cash distributions to
our unitholders;
|
|
|
|
future issuances and sales of our common units; and
|
|
|
|
changes in general conditions in the U.S. economy,
financial markets or the oil and natural gas industry.
|
In recent years, the securities market has experienced extreme
price and volume fluctuations. This volatility has had a
significant effect on the market price of securities issued by
many companies for reasons unrelated to the operating
performance of these companies. Future market fluctuations may
result in a lower price of our common units.
Because
we are a relatively small company, the requirements of being a
public company, including compliance with the reporting
requirements of the Securities Exchange Act of 1934 and the
requirements of the Sarbanes-Oxley Act may strain our resources,
increase our costs and distract management, and we may be unable
to comply with these requirements in a timely or cost-effective
manner.
We have no history operating as a publicly-traded company. As a
public company with listed equity securities, we will need to
comply with new laws, regulations and requirements, including
certain corporate governance provisions of the Sarbanes-Oxley
Act of 2002, related regulations of the SEC and the requirements
of NASDAQ, with which we are not required to comply as a private
company. Complying with these statutes, regulations and
requirements will require a significant amount of time from our
general partners board of directors and management and
will significantly increase our legal and financial compliance
costs and make such compliance more time-consuming and costly.
We will need to:
|
|
|
|
|
institute a more comprehensive compliance function;
|
|
|
|
design, establish, evaluate and maintain a system of internal
controls over financial reporting in compliance with the
requirements of Section 404 of the Sarbanes-Oxley Act of
2002 and the related rules and regulations of the SEC and the
Public Company Accounting Oversight Board;
|
|
|
|
comply with rules promulgated by NASDAQ;
|
|
|
|
prepare and distribute periodic public reports in compliance
with our obligations under the federal securities laws;
|
|
|
|
establish new internal policies, such as those relating to
disclosure controls and procedures and insider trading;
|
|
|
|
involve and retain to a greater degree outside counsel and
accountants in the above activities; and
|
|
|
|
establish an investor relations function.
|
In addition, we also expect that being a public company subject
to these rules and regulations will make it more difficult and
expensive for our general partner to obtain director and officer
liability insurance and we may be required to accept greater
coverage than we desire or to incur substantial costs to obtain
coverage.
51
These factors could also make it more difficult for our general
partner to attract and retain qualified executive officers and
qualified members to serve on its board of directors,
particularly the audit committee of the board of directors. We
have included $2.5 million of estimated incremental costs
associated with being a publicly traded partnership in our
financial forecast included elsewhere in this prospectus;
however, it is possible that our actual incremental costs of
being a publicly traded partnership will be higher than we
currently estimate.
We are not currently required to comply with the SECs
rules implementing Section 404 of the Sarbanes-Oxley Act of
2002 and are therefore not required to make a formal assessment
of the effectiveness of our internal control over financial
reporting for that purpose. Upon becoming a public company, we
will be required to comply with the SECs rules
implementing Section 302 of the Sarbanes-Oxley Act of 2002,
which will require our management to certify financial and other
information in our quarterly and annual reports and provide an
annual management report on the effectiveness of our internal
control over financial reporting. We will not be required to
make our first assessment of our internal control over financial
reporting until the year following our first annual report
required to be filed with the SEC. To comply with the
requirements of being a public company, we will need to upgrade
our systems, including information technology, implement
additional financial and management controls, reporting systems
and procedures and hire additional accounting, finance and legal
staff.
Our efforts to develop and maintain our internal controls may
not be successful, and we may be unable to maintain effective
controls over our financial processes and reporting in the
future and comply with the certification and reporting
obligations under Sections 302 and 404 of the
Sarbanes-Oxley Act. Further, our remediation efforts may not
enable us to remedy or avoid material weaknesses or significant
deficiencies in the future. Any failure to remediate material
weaknesses or significant deficiencies and to develop or
maintain effective controls, or any difficulties encountered in
our implementation or improvement of our internal controls over
financial reporting could result in material misstatements that
are not prevented or detected on a timely basis, which could
potentially subject us to sanctions or investigations by the
SEC, NASDAQ or other regulatory authorities. Ineffective
internal controls could also cause investors to lose confidence
in our reported financial information.
Our
unitholders will experience immediate and substantial dilution
of $ per unit.
The assumed initial offering price of
$ per common unit exceeds our pro
forma net tangible book value after this offering of
$ per common unit. Based on the
assumed initial offering price of
$ per common unit, our unitholders
will incur immediate and substantial dilution of
$ per common unit. This dilution
will occur primarily because the assets contributed by
affiliates of our general partner are recorded, in accordance
with GAAP at their historical cost, and not their fair value.
The impact of such dilution would be magnified upon any
conversion of the incentive distribution rights into common
units. Please read Dilution.
Our
partnership agreement requires that we distribute all of our
available cash, which could limit our ability to grow our
reserves and production.
Our partnership agreement provides that we will distribute all
of our available cash each quarter. As a result, we may be
dependent on the issuance of additional common units and other
partnership securities and borrowings to finance our growth. A
number of factors will affect our ability to issue securities
and borrow money to finance growth, as well as the costs of such
financings, including:
|
|
|
|
|
general economic and market conditions, including interest
rates, prevailing at the time we desire to issue securities or
borrow funds;
|
|
|
|
conditions in the oil and natural gas industry;
|
|
|
|
the market price of, and demand for, our common units;
|
|
|
|
our results of operations and financial condition; and
|
|
|
|
prices for oil and natural gas.
|
52
NASDAQ
does not require a publicly traded limited partnership like us
to comply with certain of its corporate governance
requirements.
We intend to list our common units on NASDAQ. Because we will be
a publicly traded limited partnership, NASDAQ does not require
us to have a majority of independent directors on our general
partners board of directors or to establish a compensation
committee or a nominating and corporate governance committee.
Accordingly, unitholders will not have the same protections
afforded to certain corporations that are subject to all of
NASDAQ corporate governance requirements. Please read
Management Management of Memorial Production
Partners LP.
Tax Risks
to Unitholders
In addition to reading the following risk factors, prospective
unitholders should read Material Tax Consequences
for a more complete discussion of the expected material federal
income tax consequences of owning and disposing of our units.
Our
tax treatment depends on our status as a partnership for federal
income tax purposes. If the IRS were to treat us as a
corporation for federal income tax purposes, then our cash
available for distribution to our unitholders would be
substantially reduced.
The anticipated after-tax economic benefit of an investment in
the units depends largely on our being treated as a partnership
for federal income tax purposes. We have not requested, and do
not plan to request, a ruling from the IRS on this or any other
tax matter affecting us.
Despite the fact that we are a limited partnership under
Delaware law, it is possible in certain circumstances for a
partnership such as ours to be treated as a corporation for
federal income tax purposes. Although we do not believe based on
our current operations that we are or will be so treated, a
change in our business (or a change in current law) could cause
us to be treated as a corporation for federal income tax
purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income
at the corporate tax rate, which is currently a maximum of 35%
and would likely pay state income tax at varying rates.
Distributions to unitholders would generally be taxed again as
corporate distributions, and no income, gains, losses or
deductions would flow through to unitholders. Because a tax
would be imposed upon us as a corporation, our cash available
for distribution to unitholders would be substantially reduced.
Therefore, treatment of us as a corporation would result in a
material reduction in the anticipated cash flow and after-tax
return to our unitholders, likely causing a substantial
reduction in the value of our units.
If we
were subjected to a material amount of additional entity-level
taxation by individual states, it would reduce our cash
available for distribution to our unitholders.
Changes in current state law may subject us to additional
entity-level taxation by individual states. Because of
widespread state budget deficits and other reasons, several
states are evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income,
franchise and other forms of taxation. For example, we are
required to pay Texas franchise tax each year at a maximum
effective rate of 0.7% of our gross income apportioned to Texas
in the prior year. Imposition of any similar taxes by any other
state may substantially reduce the cash available for
distribution to our unitholders and, therefore, negatively
impact the value of an investment in our units. Our partnership
agreement provides that if a law is enacted or existing law is
modified or interpreted in a manner that subjects us to
additional amounts of entity-level taxation for state or local
income tax purposes, the minimum quarterly distribution amount
and the target distribution levels may be adjusted to reflect
the impact of that law on us.
53
The
tax treatment of publicly traded partnerships or an investment
in our units could be subject to potential legislative, judicial
or administrative changes and differing interpretations,
possibly on a retroactive basis.
The present federal income tax treatment of publicly traded
partnerships, including us, or an investment in our units may be
modified by administrative, legislative or judicial
interpretation at any time. For example, members of Congress
have recently considered substantive changes to the existing
federal income tax laws that would affect the tax treatment of
certain publicly traded partnerships. Any modification to the
federal income tax laws and interpretations thereof may or may
not be applied retroactively. We are unable to predict whether
any of these changes, or other proposals, will ultimately be
enacted. Any such changes could negatively impact the value of
an investment in our units.
Our partnership agreement provides that if a law is enacted or
existing law is modified or interpreted in a manner that
subjects us to taxation as a corporation or otherwise subjects
us to entity-level taxation for federal income tax purposes, the
minimum quarterly distribution and the target distribution
levels may be adjusted to reflect the impact of that law on us.
Certain
U.S. federal income tax deductions currently available with
respect to oil and natural gas exploration and production may be
eliminated as a result of future legislation.
President Obamas Proposed Fiscal Year 2012 Budget includes
proposed legislation that would, if enacted into law, make
significant changes to United States tax laws, including the
elimination of certain key U.S. federal income tax
incentives currently available to oil and natural gas
exploration and production companies. These changes include, but
are not limited to, (i) the repeal of the percentage
depletion allowance for oil and natural gas properties,
(ii) the elimination of current deductions for intangible
drilling and development costs, or IDCs, (iii) the
elimination of the deduction for certain domestic production
activities, and (iv) an extension of the amortization
period for certain geological and geophysical expenditures. It
is unclear whether these or similar changes will be enacted and,
if enacted, how soon any such changes could become effective.
The passage of any legislation as a result of these proposals or
any other similar changes in U.S. federal income tax laws
could eliminate or postpone certain tax deductions that are
currently available with respect to oil and natural gas
exploration and development, and any such change could increase
the taxable income allocable to our unitholders and negatively
impact the value of an investment in our units.
If the
IRS contests any of the federal income tax positions we take,
the market for our units may be adversely affected, and the
costs of any IRS contest will reduce our cash available for
distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our
treatment as a partnership for federal income tax purposes or
any other matter affecting us. The IRS may adopt positions that
differ from the conclusions of our counsel expressed in this
prospectus or from the positions we take. It may be necessary to
resort to administrative or court proceedings to sustain some or
all of our counsels conclusions or the positions we take.
A court may not agree with some or all of our counsels
conclusions or the positions we take. Any contest with the IRS
may materially and adversely impact the market for our units and
the price at which they trade. In addition, the costs of any
contest with the IRS will be borne indirectly by our unitholders
and our general partner because the costs will reduce our cash
available for distribution.
Our
unitholders will be required to pay taxes on their share of our
income even if they do not receive any cash distributions from
us.
Because our unitholders will be treated as partners to whom we
will allocate taxable income, which could be different in amount
than the cash we distribute, our unitholders will be required to
pay any federal income taxes and, in some cases, state and local
income taxes on their share of our taxable income even if they
receive no cash distributions from us. Our unitholders may not
receive cash distributions from us equal to their share of our
taxable income or even equal to the actual tax liability that
results from that income.
54
Tax
gain or loss on the disposition of our units could be more or
less than expected.
If our unitholders sell their units, they will recognize a gain
or loss equal to the difference between the amount realized and
their tax basis in those units. Because distributions in excess
of their allocable share of our total net taxable income
decrease their tax basis in their units, the amount, if any, of
such prior excess distributions with respect to the units they
sell will, in effect, become taxable income to them if they sell
such units at a price greater than their tax basis in those
units, even if the price they receive is less than their
original cost. Furthermore, a substantial portion of the amount
realized, whether or not representing gain, may be taxed as
ordinary income due to potential recapture items, including
depreciation, depletion and IDC recapture. In addition, because
the amount realized may include a unitholders share of our
nonrecourse liabilities, if they sell their units, they may
incur a tax liability in excess of the amount of cash they
receive from the sale. Please read Material Tax
Consequences Disposition of Common Units
Recognition of Gain or Loss.
Tax-exempt
entities and
non-U.S.
persons face unique tax issues from owning our units that may
result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee
benefit plans and individual retirement accounts, or IRAs, and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to organizations that are exempt from federal
income tax, including IRAs and other retirement plans, will be
unrelated business taxable income and will be taxable to them.
Distributions to
non-U.S. persons
will be reduced by withholding taxes at the highest applicable
effective tax rate, and
non-U.S. persons
will be required to file U.S. federal income tax returns
and pay tax on their share of our taxable income. Prospective
unitholders who are tax-exempt entities or
non-U.S. persons
should consult their tax advisor before investing in our units.
We
will treat each purchaser of units as having the same tax
benefits without regard to the actual units purchased. The IRS
may challenge this treatment, which could adversely affect the
value of the units.
Because we cannot match transferors and transferees of units and
because of other reasons, we will adopt depreciation, depletion
and amortization positions that may not conform with all aspects
of existing Treasury Regulations. A successful IRS challenge to
those positions could adversely affect the amount of tax
benefits available to our unitholders. It also could affect the
timing of these tax benefits or the amount of gain from the sale
of units and could have a negative impact on the value of our
units or result in audit adjustments to a unitholders tax
returns. Please read Material Tax Consequences
Tax Consequences of Unit Ownership Section 754
Election for a further discussion of the effect of the
depreciation, depletion and amortization positions we will adopt.
We
will prorate our items of income, gain, loss and deduction for
U.S. federal income tax purposes between transferors and
transferees of our units each month based upon the ownership of
our units on the first day of each month, instead of on the
basis of the date a particular unit is transferred. The IRS may
challenge this treatment, which could change the allocation of
items of income, gain, loss and deduction among our
unitholders.
We will prorate our items of income, gain, loss and deduction
for U.S. federal income tax purposes between transferors
and transferees of our units each month based upon the ownership
of our units on the first day of each month, instead of on the
basis of the date a particular unit is transferred. The use of
this proration method may not be permitted under existing
Treasury Regulations. Recently, however, the U.S. Treasury
Department issued proposed Treasury Regulations that provide a
safe harbor pursuant to which publicly traded partnerships may
use a similar monthly simplifying convention to allocate tax
items among transferor and transferee unitholders. Nonetheless,
the proposed regulations do not specifically authorize the use
of the proration method we have adopted. If the IRS were to
challenge our proration method or new Treasury Regulations were
issued, we may be required to change the allocation of items of
income, gain, loss and deduction among our unitholders. Akin
Gump Strauss Hauer & Feld LLP has not rendered an
opinion with respect to whether our monthly convention for
allocating taxable income and losses is permitted by existing
55
Treasury Regulations. Please read Material Tax
Consequences Disposition of Common Units
Allocations Between Transferors and Transferees.
A
unitholder whose units are loaned to a short seller
to cover a short sale of units may be considered to have
disposed of those units. If so, he would no longer be treated
for federal income tax purposes as a partner with respect to
those units during the period of the loan and may recognize gain
or loss from the disposition.
Because a unitholder whose units are loaned to a short
seller to cover a short sale of units may be considered as
having disposed of the loaned units, he may no longer be treated
for tax purposes as a partner with respect to those units during
the period of the loan to the short seller and the unitholder
may recognize gain or loss from such disposition. Moreover,
during the period of the loan to the short seller, any of our
income, gain, loss or deduction with respect to those units may
not be reportable by the unitholder and any cash distributions
received by the unitholder as to those units could be fully
taxable as ordinary income. Akin Gump Strauss Hauer &
Feld LLP has not rendered an opinion regarding the treatment of
a unitholder where units are loaned to a short seller to cover a
short sale of units; therefore, unitholders desiring to assure
their status as partners and avoid the risk of gain recognition
from a loan to a short seller are urged to modify any applicable
brokerage account agreements to prohibit their brokers from
borrowing their units.
We
will adopt certain valuation methodologies and monthly
conventions for U.S. federal income tax purposes that may result
in a shift of income, gain, loss and deduction between our
general partner and our unitholders. The IRS may challenge this
treatment, which could adversely affect the value of our common
units.
When we issue additional units or engage in certain other
transactions, we will determine the fair market value of our
assets and allocate any unrealized gain or loss attributable to
our assets to the capital accounts of our unitholders and our
general partner. Our methodology may be viewed as understating
the value of our assets. In that case, there may be a shift of
income, gain, loss and deduction between certain unitholders and
the general partner, which may be unfavorable to such
unitholders. Moreover, under our current valuation methods,
subsequent purchasers of common units may have a greater portion
of their Internal Revenue Code Section 743(b) adjustment
allocated to our tangible assets and a lesser portion allocated
to our intangible assets. The IRS may challenge our valuation
methods, or our allocation of the Section 743(b) adjustment
attributable to our tangible and intangible assets, and
allocations of taxable income, gain, loss and deduction between
the general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
taxable gain from our unitholders sale of common units and
could have a negative impact on the value of the common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions. Akin Gump Strauss
Hauer & Feld LLP has not rendered an opinion with
respect to whether our method for depreciating Section 743
adjustments is sustainable in certain cases.
The
sale or exchange of 50% or more of our capital and profits
interests during any twelve-month period will result in the
termination of our partnership for federal income tax
purposes.
We will be considered to have technically terminated for federal
income tax purposes if there is a sale or exchange of 50% or
more of the total interests in our capital and profits within a
twelve-month period. For purposes of determining whether the 50%
threshold has been met, multiple sales of the same unit will be
counted only once. While we would continue our existence as a
Delaware limited partnership, our technical termination would,
among other things, result in the closing of our taxable year
for all unitholders, which would result in us filing two tax
returns (and our unitholders could receive two Schedules K-1 if
relief was not available, as described below) for one fiscal
year and could result in a significant deferral of depreciation
deductions allowable in computing our taxable income. In the
case of a unitholder reporting on a taxable year other than a
fiscal year ending December 31, the closing of our taxable
year may also result in more than twelve months of our taxable
income or loss being includable in his taxable income for the
year of
56
termination. A technical termination would not affect our
classification as a partnership for federal income tax purposes,
but instead, we would be treated as a new partnership for tax
purposes. If treated as a new partnership, we must make new tax
elections and could be subject to penalties if we are unable to
determine that a technical termination occurred. The IRS has
recently announced a relief procedure whereby if a publicly
traded partnership that has technically terminated requests and
the IRS grants special relief, among other things, the
partnership will be required to provide only a single
Schedule K-1
to unitholders for the tax years in which the termination
occurs. Please read Material Tax Consequences
Disposition of Common Units Constructive
Termination for a discussion of the consequences of our
termination for federal income tax purposes.
As a
result of investing in our units, our unitholders may become
subject to state and local taxes and return filing requirements
in jurisdictions where we operate or own or acquire
property.
In addition to federal income taxes, our unitholders will likely
be subject to other taxes, including foreign, state and local
taxes, unincorporated business taxes and estate, inheritance or
intangible taxes that are imposed by the various jurisdictions
in which we conduct business or own property now or in the
future even if such unitholders do not live in those
jurisdictions. Our unitholders likely will be required to file
state and local income tax returns and pay state and local
income taxes in some or all of these various jurisdictions.
Further, unitholders may be subject to penalties for failure to
comply with those requirements. We initially will own property
and conduct business in Texas and Louisiana. Louisiana currently
imposes a personal income tax on individuals. These states also
impose an income tax on corporations and other entities. As we
make acquisitions or expand our business, we may own assets or
conduct business in additional states that impose a personal
income tax. We may own property or conduct business in other
states or foreign countries in the future. It is a
unitholders responsibility to file all U.S. federal,
state and local tax returns. Akin Gump Strauss Hauer &
Feld LLP has not rendered an opinion on the state or local tax
consequences of an investment in our units.
57
USE OF
PROCEEDS
We intend to use the estimated net proceeds of approximately
$ million from this offering,
based upon the assumed initial public offering price of
$ per common unit (the midpoint of
the price range set forth on the cover of this prospectus),
after deducting underwriting discounts, structuring fees and
offering expenses, together with borrowings of approximately
$130.0 million under our new revolving credit facility, as
partial consideration (together with our issuance to Memorial
Resource
of
common units
and
subordinated units) for the contribution by Memorial Resource
and its subsidiaries (including our predecessor) of the
Partnership Properties and to pay fees and expenses associated
with such contribution and this offering.
The following table illustrates our use of the proceeds of this
offering and our borrowings under our new revolving credit
facility.
|
|
|
|
|
|
|
|
|
|
|
Sources of Cash (In millions)
|
|
|
Uses of Cash (In millions)
|
|
|
Gross proceeds from this offering(1)
|
|
$
|
|
|
|
Cash consideration to Memorial Resource
|
|
$
|
|
|
Borrowings under new revolving credit facility(1)
|
|
|
130.0
|
|
|
Underwriting discounts, structuring fees and other offering and
formation-related fees and expenses payable by us
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
Total
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
If the underwriters exercise their option to purchase additional
common units in full, the gross proceeds would be
$ and the amount borrowed under our
new revolving credit facility would be approximately
$ million. |
We will use any net proceeds from the exercise of the
underwriters option to purchase additional common units to
reduce outstanding borrowings under our new revolving credit
facility. If the underwriters exercise in full their option to
purchase additional common units, the ownership interest of the
public unitholders will increase
to
common units representing an
aggregate % limited partner
interest in us and the ownership interest of our general partner
will increase
to
general partner units representing a 0.1% general partner
interest in us. Please read Underwriting.
Our estimates assume an initial public offering price of
$ per common unit (the midpoint of
the price range set forth on the cover of this prospectus) and
no exercise of the underwriters option to purchase
additional common units. An increase or decrease in the initial
public offering price of $1.00 per common unit would cause the
net proceeds from this offering, after deducting underwriting
discounts, to increase or decrease by
$ million, and would result
in a corresponding decrease or increase, respectively, in the
amount borrowed under our new revolving credit facility.
58
CAPITALIZATION
The following table shows:
|
|
|
|
|
the historical capitalization of our predecessor as of
March 31, 2011; and
|
|
|
|
our pro forma capitalization as of March 31, 2011, adjusted
to reflect the issuance and sale of common units to the public
at an assumed initial offering price of
$ per common unit (the midpoint of
the price range set forth on the cover of this prospectus), the
other formation transactions described under
Summary Our Partnership Structure and
Formation Transactions, and the application of the net
proceeds from this offering as described under Use of
Proceeds.
|
We derived this table from, and it should be read in conjunction
with and is qualified in its entirety by reference to, the
historical and unaudited pro forma financial statements and the
accompanying notes included elsewhere in this prospectus. You
should also read this table in conjunction with
Summary Our Partnership Structure and
Formation Transactions, Use of Proceeds and
Managements Discussion and Analysis of Financial
Condition and Results of Operations. For a description of
the pro forma adjustments, please read our Unaudited Pro Forma
Combined Financial Statements.
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2011
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
Our
|
|
|
Memorial
|
|
|
|
Predecessor
|
|
|
Production
|
|
|
|
Historical
|
|
|
Partners LP
|
|
|
|
(In thousands)
|
|
|
Long-term debt(1)
|
|
$
|
112,506
|
|
|
$
|
|
|
Partners capital/net equity:
|
|
|
|
|
|
|
|
|
Predecessor partners capital
|
|
|
108,039
|
|
|
|
|
|
Common units held by purchasers in this offering
|
|
|
|
|
|
|
|
|
Common units held by Memorial Resource
|
|
|
|
|
|
|
|
|
Subordinated units held by Memorial Resource
|
|
|
|
|
|
|
|
|
General partner interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total partners capital/net equity(2)
|
|
|
108,039
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
$
|
220,545
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We intend to enter into a
$ million revolving credit
facility, approximately
$ million of which will be
available for borrowing upon the completion of the transactions
described under Summary Our Partnership
Structure and Formation Transactions. After giving effect
to the transactions described under Summary
Our Partnership Structure and Formation Transactions,
including our expected borrowing of $130.0 million under
our new revolving credit facility, we will have approximately
$ million of borrowing
capacity. For additional information on our new revolving credit
facility, please read Managements Discussion and
Analysis of Financial Condition and Results of
Operations Pro Forma Liquidity and Capital
Resources New Revolving Credit Facility. |
|
(2) |
|
A $1.00 increase or decrease in the assumed initial public
offering price per common unit would increase or decrease,
respectively, the net proceeds by approximately
$ million, would result in a
corresponding decrease or increase in the amount borrowed under
our new revolving credit facility, and would change our total
partners capital by approximately
$ million, assuming the
number of common units offered by us, as set forth on the cover
page of this prospectus, remains the same. |
This table does not reflect the issuance of up to an
additional
common units that may be sold to the underwriters upon exercise
of their option to purchase additional common units.
59
DILUTION
Dilution is the amount by which the offering price paid by the
purchasers of common units sold in this offering will exceed the
pro forma as adjusted net tangible book value per unit after
this offering. Net tangible book value is our total tangible
assets less total liabilities. Assuming an initial offering
price of $ per common unit (the
midpoint of the price range set forth on the cover of this
prospectus), on a pro forma as adjusted basis as of
March 31, 2011, after giving effect to the transactions
described under Summary Our Partnership
Structure and Formation Transactions, including this
offering of common units and the application of the related net
proceeds and assuming the underwriters option to purchase
additional common units is not exercised, our pro forma as
adjusted net tangible book value was
$ million, or
$ per unit. Purchasers of common
units in this offering will experience substantial and immediate
dilution in net tangible book value per common unit for
accounting purposes, as illustrated in the following table:
|
|
|
|
|
|
|
|
|
Assumed initial offering price per common unit
|
|
|
|
|
|
$
|
|
|
Pro forma as adjusted net tangible book value per unit before
this offering(1)
|
|
$
|
|
|
|
|
|
|
Increase in net tangible book value per unit attributable to
purchasers in this offering
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less: Pro forma as adjusted net tangible book value per unit
after this offering(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Immediate dilution in net tangible book value per unit to
purchasers in this offering(3)
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Determined by dividing the pro forma net tangible book value of
our net assets immediately prior to the offering by the number
of units
(
common units
and
subordinated units) to be issued to Memorial Resource as partial
consideration for their contribution of the Partnership
Properties to us and
the
general partner units to be issued to our general partner. |
|
(2) |
|
Determined by dividing our pro forma as adjusted net tangible
book value, after giving effect to the application of the
expected net proceeds of this offering, by the total number of
units to be outstanding after this offering
( common
units, subordinated
units,
and general
partner units). |
|
(3) |
|
If the assumed initial offering price were to increase or
decrease by $1.00 per common unit, then dilution in pro forma as
adjusted net tangible book value per unit would equal
$ or
$ , respectively. The information
discussed above is illustrative only and will be adjusted based
on the actual public offering price and other terms of this
offering determined at pricing. |
The following table sets forth the number of units that we will
issue and the total consideration contributed to us by our
general partner and its affiliates, including Memorial Resource,
in respect of their units and by the purchasers of common units
in this offering upon consummation of the transactions
contemplated by this prospectus:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Units Acquired
|
|
Total Consideration
|
|
|
Number
|
|
Percent
|
|
$
|
|
Percent
|
|
|
|
|
|
|
(In millions)
|
|
|
|
General partner and its affiliates(1)(2)
|
|
|
|
|
|
|
|
%
|
|
$
|
|
|
|
|
|
%
|
Purchasers in the offering(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
100.0
|
%
|
|
|
|
|
|
$
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Upon the consummation of the transactions contemplated by this
prospectus, and assuming the underwriters do not exercise their
option to purchase additional common units, our general partner
and its affiliates will
own
common
units, subordinated
units, and general partner units. |
|
(2) |
|
The assets contributed by Memorial Resource were recorded at
historical cost in accordance with GAAP. Total consideration
provided by affiliates of our general partner is equal to the
pro forma net tangible book value of such assets as of
March 31, 2011. |
|
(3) |
|
Total consideration is after deducting underwriting discounts
and estimated offering expenses. |
60
OUR CASH
DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
You should read the following discussion of our cash
distribution policy in conjunction with specific assumptions
included in this section. For more detailed information
regarding the factors and assumptions upon which our cash
distribution policy is based, please read
Estimated Adjusted EBITDA for the Twelve
Months Ending June 30, 2012 below. In addition, you
should read Forward-Looking Statements and
Risk Factors for information regarding statements
that do not relate strictly to historical or current facts and
certain risks inherent in our business.
For additional information regarding our historical and pro
forma operating results, you should refer to the audited
historical combined financial statements of our predecessor as
of and for the three years ended December 31, 2010, the
unaudited historical combined financial statements of our
predecessor for the three months ended March 31, 2011 and
2010, and our unaudited pro forma combined financial statements
for the year ended December 31, 2010 and the three months
ended March 31, 2011, all included elsewhere in this
prospectus.
General
Rationale
for Our Cash Distribution Policy
Our partnership agreement requires us to distribute all of our
available cash on a quarterly basis. Our available cash is our
cash on hand at the end of a quarter after the payment of our
expenses and the establishment of reserves for future capital
expenditures, operational needs and certain future
distributions, including cash from borrowings. We intend to fund
a portion of our capital expenditures with additional borrowings
or issuances of additional units. We may also borrow to make
distributions to unitholders, for example, in circumstances
where we believe that the distribution level is sustainable over
the long term, but short-term factors have caused available cash
from operations to be insufficient to pay the distribution at
the current level. Our cash distribution policy reflects a basic
judgment that our unitholders will be better served by us
distributing our available cash, after expenses and reserves,
rather than retaining it. Also, because we are not subject to an
entity-level federal income tax, we will have more cash to
distribute to our unitholders than would be the case if we were
subject to federal income tax.
Restrictions
and Limitations on Cash Distributions and Our Ability to Change
Our Cash Distribution Policy
There is no guarantee that unitholders will receive quarterly
distributions from us. We do not have a legal obligation to pay
the minimum quarterly distribution or distributions at any other
rate except as provided in our partnership agreement. Our
distribution policy is subject to certain restrictions and may
be changed at any time, including:
|
|
|
|
|
Our cash distribution policy may be subject to restrictions on
distributions under our new revolving credit facility or other
debt agreements that we may enter into in the future.
Specifically, we anticipate that the agreement related to our
new revolving credit facility will contain financial tests and
covenants that we must satisfy. These financial ratios and
covenants are described under the caption
Managements Discussion and Analysis of Financial
Condition and Results of Operations Pro Forma
Liquidity and Capital Resources New Revolving Credit
Facility. Should we be unable to satisfy these
restrictions, or if a default occurs under our new revolving
credit facility, we would be prohibited from making cash
distributions to our unitholders notwithstanding our stated cash
distribution policy.
|
|
|
|
Our general partner will have the authority to establish
reserves for the prudent conduct of our business and for future
cash distributions to our unitholders, and the establishment of
or increase in those reserves could result in a reduction in
cash distributions to our unitholders from levels we currently
anticipate under our stated distribution policy. Any
determination to establish or increase reserves made by our
general partner in good faith will be binding on the
unitholders. We intend to reserve a portion of our cash
generated from operations to fund our exploitation and
development capital expenditures.
|
61
|
|
|
|
|
Over a longer period of time, if our general partner does not
set aside sufficient cash reserves or make sufficient cash
expenditures to maintain our asset base, we will be unable to
pay the minimum quarterly distribution from cash generated from
operations and would therefore expect to reduce our
distributions. We are unlikely to be able to sustain our current
level of distributions without making accretive acquisitions or
capital expenditures that maintain the current production levels
of our oil and natural gas properties. Decreases in commodity
prices from current levels will adversely affect our ability to
pay distributions. If our asset base decreases and we do not
reduce our distributions, a portion of the distributions may be
considered a return of part of our unitholders investment
in us as opposed to a return on our unitholders investment.
|
|
|
|
|
|
Prior to making any distribution on our common units, we will
reimburse our general partner and its affiliates for all direct
and indirect expenses they incur on our behalf. Our partnership
agreement does not set a limit on the amount of expenses for
which our general partner and its affiliates may be reimbursed.
These expenses include salary, bonus, incentive compensation and
other amounts paid to persons who perform services for us or on
our behalf and expenses allocated to our general partner by its
affiliates. Our partnership agreement provides that our general
partner will determine in good faith the expenses that are
allocable to us. The reimbursement of expenses and payment of
fees, if any, to our general partner and its affiliates will
reduce the amount of cash available to pay cash distributions to
our unitholders.
|
|
|
|
Although our partnership agreement requires us to distribute all
of our available cash, our partnership agreement, including the
provisions requiring us to make cash distributions contained
therein, may be amended. Our partnership agreement may not be
amended during the subordination period without the approval of
our public common unitholders, other than in certain limited
circumstances where no unitholder approval is required. However,
our partnership agreement can be amended with the consent of our
general partner and the approval of the holders of a majority of
our outstanding common units (including common units that are
held by Memorial Resource and its affiliates) after the
subordination period has ended. Upon consummation of this
offering, Memorial Resource will own our general partner and
will control the voting of an aggregate of
approximately % of our outstanding
common units and all of our subordinated units. Assuming we do
not issue any additional common units and Memorial Resource does
not transfer its common units, Memorial Resource will have the
ability to amend our partnership agreement without the approval
of any other unitholder once the subordination period ends.
|
|
|
|
Even if our cash distribution policy is not modified or revoked,
the amount of distributions we pay under our cash distribution
policy and the decision to make any distribution is determined
by our general partner, taking into consideration the terms of
our partnership agreement, our new revolving credit facility and
any other debt agreements we may enter into in the future.
|
|
|
|
Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, we may
not make a distribution to our unitholders if the distribution
would cause our liabilities to exceed the fair value of our
assets.
|
|
|
|
We may lack sufficient cash to pay distributions to our
unitholders due to a number of factors, including reductions in
commodity prices, reductions in our oil and natural gas
production, increases in our general and administrative
expenses, principal and interest payments on our outstanding
debt, tax expenses, working capital requirements and anticipated
cash needs. For a discussion of additional factors that may
affect our ability to pay distributions, please read Risk
Factors.
|
|
|
|
If and to the extent our cash available for distribution
materially declines, we may reduce our quarterly distribution in
order to service or repay our debt or fund growth capital
expenditures.
|
|
|
|
All available cash distributed by us on any date from any source
will be treated as distributed from operating surplus until the
sum of all available cash distributed since the closing of this
offering equals the cumulative operating surplus from the
closing of this offering through the end of the quarter
immediately preceding that distribution. We anticipate that
distributions from operating surplus will
|
62
|
|
|
|
|
generally not represent a return of capital. However, operating
surplus, as defined in our partnership agreement, includes
certain components that represent non-operating sources of cash,
including a $ million cash
basket and working capital borrowings. Consequently, it is
possible that distributions from operating surplus may represent
a return of capital. For example, the
$ million cash basket would
allow us to distribute as operating surplus cash proceeds we
receive from non-operating sources, such as assets sales,
issuances of securities and long-term borrowings, which would
represent a return of capital. Distributions representing a
return of capital could result in a corresponding decrease in
our asset base. Additionally, any cash distributed by us in
excess of operating surplus will be deemed to be capital surplus
under our partnership agreement. Our partnership agreement
treats a distribution of capital surplus as the repayment of the
initial unit price from this initial public offering, which is
similar to a return of capital. Distributions from capital
surplus could result in a corresponding decrease in our asset
base. We do not anticipate that we will make any distributions
from capital surplus. Please read Provisions of Our
Partnership Agreement Relating to Cash Distributions
Operating Surplus and Capital Surplus and Provisions
of Our Partnership Agreement Relating to Cash
Distributions Distributions from Capital
Surplus Effect of a Distribution from Capital
Surplus.
|
Our
Ability to Grow Depends on Our Ability to Access External Growth
Capital
Our partnership agreement requires us to distribute all of our
available cash to unitholders on a quarterly basis. As a result,
we expect that we will rely primarily upon external financing
sources, including commercial bank borrowings and the issuance
of debt and equity interests, rather than cash reserves
established by our general partner, to fund our growth capital
expenditures. To the extent we are unable to finance our growth
externally, our cash distribution policy will significantly
impair our ability to grow. In addition, because we will
distribute all of our available cash, our growth may not be as
fast as that of businesses that reinvest their available cash to
expand their ongoing operations. To the extent we issue
additional units in connection with any growth capital
expenditures, the payment of distributions on those additional
units may increase the risk that we will be unable to maintain
or increase our quarterly per unit distribution level. There are
no limitations in our partnership agreement or our new revolving
credit facility on our ability to issue additional units,
including units ranking senior to the common units. The
incurrence of additional commercial borrowings or other debt to
finance our growth strategy would result in increased interest
expense, which in turn may impact the available cash that we
have to distribute to our unitholders.
Our
Minimum Quarterly Distribution
Upon completion of this offering, the board of directors of our
general partner will establish a minimum quarterly distribution
of $ per unit per whole quarter,
or $ per unit per year on an
annualized basis, to be paid no later than 45 days after
the end of each fiscal quarter beginning with the quarter
ending .
This equates to an aggregate cash distribution of approximately
$ million per quarter or
$ million per year, in each
case based on the number of common units, subordinated units and
general partner units outstanding immediately after completion
of this offering, but excluding any common units that may be
issued under the long-term incentive plan that our general
partner is expected to adopt prior to the closing of this
offering. If the underwriters exercise their option to purchase
additional common units in
full, common
units, subordinated units
and
general partner units will be outstanding, which equates to an
aggregate cash distribution of approximately
$ million per quarter or
$ million per year. Our
ability to make cash distributions at the minimum quarterly
distribution will be subject to the factors described above
under the caption General
Restrictions and Limitations on Cash Distributions
and Our Ability to Change Our Cash Distribution Policy.
As of the date of this offering, our general partner will be
entitled to 0.1% of all distributions of available cash that we
make prior to our liquidation. Our general partners
initial 0.1% interest in these distributions may be reduced if
we issue additional units in the future and our general partner
does not contribute a proportionate amount of capital to us to
maintain its initial 0.1% general partner interest. Our general
partner is not obligated to contribute a proportionate amount of
capital to us to maintain its current general partner
63
interest. Our general partner will also hold the incentive
distribution rights, which entitle the holder to additional
increasing percentages, up to a maximum of 24.9%, of the cash we
distribute in excess of $ per
common unit per quarter.
The table below sets forth the assumed number of outstanding
common (assuming no exercise and full exercise of the
underwriters option to purchase additional common units),
subordinated and general partner units upon the closing of this
offering and the aggregate distribution amounts payable on such
units during the year following the closing of this offering at
our minimum quarterly distribution of
$ per unit per quarter, or
$ per unit on an annualized basis.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No Exercise of the Underwriters
|
|
|
Full Exercise of the Underwriters
|
|
|
|
Option to Purchase Additional Common Units
|
|
|
Option to Purchase Additional Common Units
|
|
|
|
|
|
|
Distributions
|
|
|
|
|
|
Distributions
|
|
|
|
Number of
|
|
|
One
|
|
|
Four
|
|
|
Number of
|
|
|
One
|
|
|
Four
|
|
|
|
Units
|
|
|
Quarter
|
|
|
Quarters
|
|
|
Units
|
|
|
Quarter
|
|
|
Quarters
|
|
|
Common units held by purchasers in this offering(1)
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
Common units held by Memorial Resource and its affiliates(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Does not include any common units that may be issued under the
long-term incentive plan that our general partner is expected to
adopt prior to the closing of this offering. |
If the minimum quarterly distribution on our common units is not
paid with respect to any quarter, the common unitholders will
not be entitled to receive such payments in the future except
that, during the subordination period, to the extent we
distribute cash in any future quarter in excess of the amount
necessary to make cash distributions at the minimum quarterly
distribution to holders of our common units, we will use this
excess cash to pay any of these arrearages related to prior
quarters before any cash distribution is made to holders of
subordinated units. Please read Provisions of Our
Partnership Agreement Relating to Cash Distributions
Subordination Period.
We do not have a legal obligation to pay the minimum quarterly
distribution or distributions at any other rate except as
provided in our partnership agreement. Our distribution policy
is consistent with the terms of our partnership agreement, which
requires that we distribute all of our available cash quarterly.
Under our partnership agreement, available cash is defined to
generally mean, for each fiscal quarter, cash generated from our
business in excess of expenses and the amount of reserves our
general partner determines is necessary or appropriate to
provide for the prudent conduct of our business (including
payments to our general partner for reimbursement of expenses it
incurs on our behalf), to comply with applicable law, any of our
debt instruments or other agreements or to provide for future
distributions to our unitholders for any one or more of the next
four quarters. Please read Provisions of our Partnership
Agreement Relating to Cash Distributions
Distributions of Available Cash Definition of
Available Cash.
Our partnership agreement provides that any determination made
by our general partner in its capacity as our general partner
must be made in good faith and that any such determination will
not be subject to any other standard imposed by our partnership
agreement, the Delaware limited partnership statute or any other
law, rule or regulation or imposed at equity. Holders of our
common units may pursue judicial action to enforce provisions of
our partnership agreement, including those related to
requirements to make cash distributions as described above;
however, our partnership agreement provides that our general
partner is entitled to make the determinations described above
without regard to any standard other than the requirement to act
in good faith. Our partnership agreement provides that, in order
for a determination by our general
64
partner to be made in good faith, our general
partner must believe that the determination is in our best
interests.
Our cash distribution policy, as expressed in our partnership
agreement, may not be modified or repealed without amending our
partnership agreement. The actual amount of our cash
distributions for any quarter is subject to fluctuation based on
the amount of cash we generate from our business and the amount
of reserves our general partner establishes in accordance with
our partnership agreement as described above. Our partnership
agreement, including provisions contained therein requiring us
to make cash distributions, may be amended by a vote of the
holders of a majority of our common units. Upon consummation of
this offering, Memorial Resource will own our general partner,
approximately % of our outstanding
common units and all of our subordinated units. Assuming we do
not issue any additional common units and Memorial Resource does
not transfer a controlling portion of its equity interests in
our general partner or its common units, Memorial Resource will
have the ability to amend our partnership agreement without the
approval of any other unitholders once the subordination period
ends.
We will pay our distributions on or about the 15th of each
of February, May, August and November to holders of record on or
about the first day of each such month. If the distribution date
does not fall on a business day, we will make the distribution
on the business day immediately preceding the indicated
distribution date. For our initial quarterly distribution, we
will adjust the quarterly distribution for the period from the
closing of this offering
through ,
2011 based on the actual length of the period. We expect to pay
this initial quarterly cash distribution on or
before ,
2011.
In the sections that follow, we present in detail the basis for
our belief that we will be able to fully fund our minimum
quarterly distribution of $ per
unit each quarter for the four quarters ending June 30,
2012. In those sections, we present two tables, consisting of:
|
|
|
|
|
Unaudited Pro Forma Available Cash for the Year Ended
December 31, 2010 and Twelve Months Ended March 31,
2011, in which we present the amount of cash we would have
had available for distribution to our unitholders and our
general partner for the year ended December 31, 2010 and
the twelve months ended March 31, 2011, based on our
unaudited pro forma financial statements. Our calculation of
unaudited pro forma available cash in this table should only be
viewed as a general indication of the amount of available cash
that we might have generated had the transactions contemplated
in this prospectus occurred in an earlier period.
|
|
|
|
Estimated Cash Available for Distribution, in which
we demonstrate our ability to generate the minimum Adjusted
EBITDA necessary for us to have sufficient cash available for
distribution to pay the full minimum quarterly distribution on
all the outstanding units, including our general partner units,
for the twelve months ending June 30, 2012.
|
Unaudited
Pro Forma Available Cash for the Year Ended December 31,
2010 and Twelve Months Ended March 31, 2011
If we had completed the formation transactions contemplated in
this prospectus and the acquisition of all of the Partnership
Properties on January 1, 2010, our unaudited pro forma
available cash generated during the year ended December 31,
2010 would have been approximately $46.4 million. Assuming
the underwriters do not exercise their option to purchase
additional common units, this amount would have been sufficient
to make a cash distribution for the year ended December 31,
2010 at the minimum quarterly distribution of
$ per unit per quarter (or
$ per unit on an annualized basis)
on all of our common units, general partner units and
subordinated units. Assuming the underwriters exercise in full
their option to purchase additional common units, this amount
would have been sufficient to make a cash distribution for the
year ended December 31, 2010 at the minimum quarterly
distribution of $ per unit per
quarter (or $ per unit on an
annualized basis) on all of our common units, general partner
units and subordinated units. The number of outstanding common
and subordinated units on which we have based such belief does
not include any common units that may be issued under the
long-term incentive plan that our general partner is expected to
adopt prior to the closing of this offering.
65
If we had completed the formation transactions contemplated in
this prospectus and the acquisition of all of the Partnership
Properties on April 1, 2010, our unaudited pro forma
available cash generated during the twelve months ended
March 31, 2011 would have been approximately
$40.6 million. Pro forma available cash for the twelve
months ended March 31, 2011 was negatively impacted by
non-routine items that increased lease operating expense by
approximately $1.0 million. Assuming the underwriters do
not exercise their option to purchase additional common units,
this amount would have been sufficient to make a cash
distribution for the twelve months ended March 31, 2011 at
the minimum quarterly distribution of
$ per unit per quarter (or
$ per unit on an annualized basis)
on all of our common units, general partner units and
subordinated units. Assuming the underwriters exercise in full
their option to purchase additional common units, this amount
would have been sufficient to make a cash distribution for the
twelve months ended March 31, 2011 at the minimum quarterly
distribution of $ per unit per
quarter (or $ per unit on an
annualized basis) on all of our common units and general partner
units and a quarterly distribution of
$ on
all of our subordinated units. The number of outstanding common
and subordinated units on which we have based such belief does
not include any common units that may be issued under the
long-term incentive plan that our general partner is expected to
adopt prior to the closing of this offering.
Unaudited pro forma available cash also includes general and
administrative expenses, which were calculated on a different
basis as compared to historical periods. These general and
administrative expenses are expected to total $5.0 million
annually and consist of $2.5 million of general and
administrative expenses allocated to us by Memorial Resource as
well as $2.5 million of general and administrative expenses
we expect to incur as a result of becoming a publicly traded
partnership. Our general partner is entitled to determine in
good faith the general and administrative expenses to be
reimbursed by us in accordance with our partnership agreement.
Please read Certain Relationships and Related Party
Transactions Agreements Governing the
Transactions Omnibus Agreement. We will incur
general and administrative expenses related to being a publicly
traded partnership, which will include expenses associated with
annual and quarterly reporting; tax return and
Schedule K-1
preparation and distribution expenses; Sarbanes-Oxley compliance
expenses; expenses associated with listing on NASDAQ;
independent auditor fees; legal fees; investor relations
expenses; and registrar and transfer agent fees. These expenses
are not reflected in the historical combined financial
statements of our predecessor or our pro forma combined
financial statements.
We based the pro forma adjustments upon currently available
information and specific estimates and assumptions. The pro
forma amounts below do not purport to present our results of
operations had the transactions contemplated in this prospectus
and the acquisition of all of our properties actually been
completed as of the dates presented. In addition, cash available
to pay distributions is primarily a cash accounting concept,
while our unaudited pro forma financial statements have been
prepared on an accrual basis. As a result, you should view the
amount of unaudited pro forma available cash only as a general
indication of the amount of cash available to pay distributions
that we might have generated had we been formed in an earlier
period.
66
The following table illustrates, on an unaudited pro forma
basis, for the year ended December 31, 2010 and the twelve
months ended March 31, 2011, the amount of available cash
that would have been available for distribution to our
unitholders, assuming that the formation transactions (including
the acquisition of all of the Partnership Properties) and this
offering had been consummated on January 1, 2010 and
April 1, 2010, respectively and that the underwriters did
not exercise their option to purchase additional common units.
Each of the pro forma adjustments presented below is explained
in the footnotes to such adjustments.
Memorial
Production Partners LP
Unaudited Pro Forma Cash Available for Distribution
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
Year Ended
|
|
|
Twelve Months Ended
|
|
|
|
December 31, 2010
|
|
|
March 31, 2011
|
|
|
|
(In thousands, except per unit data)
|
|
|
Net income (loss)
|
|
$
|
12,303
|
|
|
$
|
2,546
|
|
Interest expense
|
|
|
4,365
|
|
|
|
4,441
|
|
Income tax expense
|
|
|
225
|
|
|
|
225
|
|
Depreciation, depletion and amortization
|
|
|
34,772
|
|
|
|
32,655
|
|
Impairment
|
|
|
9,509
|
|
|
|
7,818
|
|
Accretion of asset retirement obligations
|
|
|
1,072
|
|
|
|
1,143
|
|
Unrealized (gains) losses on derivative instruments
|
|
|
(2,674
|
)
|
|
|
4,927
|
|
(Gain) loss on sale of properties
|
|
|
|
|
|
|
|
|
Unit-based compensation expense
|
|
|
|
|
|
|
|
|
Exploration costs
|
|
|
36
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA(1)
|
|
$
|
59,608
|
|
|
$
|
53,791
|
|
Less:
|
|
|
|
|
|
|
|
|
Cash interest expense(2)
|
|
$
|
3,965
|
|
|
$
|
3,965
|
|
Estimated average maintenance capital expenditures(3)
|
|
|
9,200
|
|
|
|
9,200
|
|
|
|
|
|
|
|
|
|
|
Pro forma available cash(4)
|
|
$
|
46,443
|
|
|
$
|
40,626
|
|
|
|
|
|
|
|
|
|
|
Pro forma annualized distributions per unit(5)
|
|
$
|
|
|
|
$
|
|
|
Pro forma estimated annual cash distributions:
|
|
|
|
|
|
|
|
|
Distributions on common units held by purchasers in this
offering(5)
|
|
$
|
|
|
|
$
|
|
|
Distributions on common units held by Memorial Resource and its
affiliates(5)
|
|
|
|
|
|
|
|
|
Distributions on subordinated units(5)
|
|
|
|
|
|
|
|
|
Distributions on general partner units(5)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total estimated annual cash distributions(5)
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Excess (Shortfall)(5)
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Percent of minimum quarterly distributions payable to common
unitholders
|
|
|
|
|
|
|
|
|
Percent of minimum quarterly distributions payable to
subordinated unitholders
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Adjusted EBITDA is defined in Summary
Non-GAAP Financial Measures. |
|
(2) |
|
In connection with this offering, we intend to enter into a new
$ million revolving credit
facility under which we expect to incur approximately
$130.0 million of borrowings upon the closing of this
offering. If the net proceeds from this offering increase or
decrease, then our borrowing under our new |
67
|
|
|
|
|
revolving credit facility would correspondingly decrease or
increase, respectively. The pro forma cash interest expense is
based on $130.0 million of borrowings at an assumed
weighted-average rate of 3.05%. If the interest rate used to
calculate this interest were 1% higher or lower, our annual cash
interest expense would increase or decrease, respectively, by
$1.3 million. Likewise, a $1.00 increase or decrease in the
assumed initial public offering price per common unit would
result in a $ million
decrease or increase in borrowings, respectively, and a
$ million decrease or
increase in interest expense, respectively. |
|
(3) |
|
Historically, our predecessor did not make a distinction between
maintenance and growth capital expenditures. For purposes of the
presentation of Unaudited Pro Forma Cash Available for
Distribution, we have estimated that approximately
$9.2 million of our predecessors capital expenditures
were maintenance capital expenditures for the Partnership
Properties for the respective period. |
|
(4) |
|
Does not reflect impact of $2.5 million of estimated
incremental annual general and administrative expenses that we
expect to incur associated with being a publicly traded
partnership. Please read Assumptions and
Considerations Capital Expenditures and
Expenses. |
|
(5) |
|
The following table provides pro forma estimated annual cash
distributions and the excess (shortfall) if the
underwriters option to purchase additional common units is
exercised in full. |
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
Year Ended
|
|
|
Twelve Months Ended
|
|
|
|
December 31, 2010
|
|
|
March 31, 2011
|
|
|
|
(In thousands, except per unit data)
|
|
|
Pro forma annualized distributions per unit
|
|
$
|
|
|
|
$
|
|
|
Pro forma estimated annual cash distributions:
|
|
|
|
|
|
|
|
|
Distributions on common units held by purchasers in this offering
|
|
$
|
|
|
|
$
|
|
|
Distributions on common units held by Memorial Resource and its
affiliates
|
|
|
|
|
|
|
|
|
Distributions on subordinated units
|
|
|
|
|
|
|
|
|
Distributions on general partner units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total estimated annual cash distributions
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Excess (Shortfall)
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Estimated
Adjusted EBITDA for the Twelve Months Ending June 30,
2012
The cumulative amount that we would distribute for the twelve
months ending June 30, 2012, if we made distributions on
all our common units, subordinated units and general partner
units at the minimum quarterly distribution rate of
$ per unit during that period,
would be $ million if the
underwriters do not exercise their option to purchase additional
common units and $ million if
the underwriters exercise in full their option to purchase
additional common units. Based upon the assumptions and
considerations set forth in Assumptions and
Considerations, in order to fund distributions on all our
common units, subordinated units and general partner units at
the minimum quarterly distribution rate for the twelve months
ending June 30, 2012, we estimate that our minimum Adjusted
EBITDA for that period must be at least
$ million if the underwriters
do not exercise their option to purchase additional common units
and at least $ million if the
underwriters exercise in full their option to purchase
additional common units. The number of outstanding common and
subordinated units on which we have based such estimates does
not include any common units that may be issued under the
long-term incentive plan that our general partner is expected to
adopt prior to the closing of this offering.
Based on the assumptions set forth in
Assumptions and Considerations, and as
set forth in the table below, we believe that we will be able to
generate approximately
$ million in Adjusted EBITDA
during the twelve months ending June 30, 2012, which amount
we refer to as our estimated Adjusted EBITDA. We can
give you no assurance, however, that we will generate this
amount of Adjusted EBITDA during that period. There will likely
be differences between our estimated Adjusted EBITDA and our
actual results for the
68
twelve months ending June 30, 2012, and those differences
could be material. If the amount of Adjusted EBITDA that we
actually generate during the twelve months ending June 30,
2012 is less than our estimated Adjusted EBITDA, we may not be
able to pay the minimum quarterly distribution on our common
units.
Our management has prepared the prospective financial
information that is the basis of our estimated Adjusted EBITDA
below to substantiate our belief that we will have sufficient
cash to pay the minimum quarterly distribution on all
outstanding common, subordinated and general partner units for
the twelve months ending June 30, 2012. This prospective
financial information is a forward-looking statement and should
be read together with the historical and unaudited pro forma
financial statements and the accompanying notes included
elsewhere in this prospectus and Managements
Discussion and Analysis of Financial Condition and Results of
Operations. This prospective financial information was not
prepared with a view toward complying with the published
guidelines of the SEC or the guidelines established by the
American Institute of Certified Public Accountants with respect
to prospective financial information, but, in the view of our
management, was prepared on a reasonable basis, reflects the
best currently available estimates and judgments, and presents,
to the best of our managements knowledge and belief, the
assumptions and considerations on which we base our belief that
we can generate sufficient Adjusted EBITDA to pay the minimum
quarterly distribution to all of our common unitholders and
subordinated unitholders, as well as in respect of our general
partner units, for the twelve months ending June 30, 2012.
However, this prospective financial information is not fact and
may not be necessarily indicative of our actual results of
operations, and readers of this prospectus are cautioned not to
place undue reliance on this prospective financial information.
Please read Assumptions and
Considerations.
The prospective financial information included in this
prospectus has been prepared by, and is the responsibility of,
our management. KPMG has not compiled or performed any
procedures with respect to the accompanying prospective
financial information and, accordingly, KPMG does not express an
opinion or any other form of assurance with respect thereto. The
KPMG reports included in the registration statement relate to
historical financial information. Those reports do not extend to
the prospective financial information and should not be read to
do so.
When considering this prospective financial information, you
should keep in mind the risk factors and other cautionary
statements under Risk Factors. Any of the risks
discussed in this prospectus, to the extent they are realized,
could cause our actual results of operations to vary
significantly from those that would enable us to generate the
estimated Adjusted EBITDA sufficient to pay the minimum
quarterly distributions to holders of our common, subordinated
and general partner units for the twelve months ending
June 30, 2012.
We do not undertake any obligation to release publicly the
results of any future revisions we may make to this prospective
financial information or to update this prospective financial
information to reflect events or circumstances after the date of
this prospectus. Therefore, you are cautioned not to place undue
reliance on this information.
As a result of the factors described in Our
Estimated Adjusted EBITDA and Assumption
and Considerations, we believe we will be able to pay cash
distributions at the minimum quarterly distribution of
$ per unit on all outstanding
common, subordinated and general partner units for each full
calendar quarter in the twelve months ending June 30, 2012.
The number of outstanding common units on which we have based
such belief does not include any common units that may be issued
under the long-term incentive plan that our general partner is
expected to adopt prior to the closing of this offering.
Our
Estimated Adjusted EBITDA
Adjusted EBITDA is a significant financial metric that will be
used by our management to indicate (prior to the establishment
of any reserves by the board of directors of our general
partner) the cash distributions we expect to pay to our
unitholders. Specifically, we intend to use this financial
measure to assist us in determining whether we are generating
operating cash flow at a level that can sustain or support an
increase in
69
our quarterly distribution rates. As used in this prospectus,
the term Adjusted EBITDA means the sum of net income
(loss) adjusted by the following to the extent included in
calculating such net income (loss):
|
|
|
|
|
Interest expense, including realized and unrealized losses on
interest rate derivative contracts;
|
|
|
|
Income tax expense;
|
|
|
|
Depreciation, depletion and amortization;
|
|
|
|
Impairment of goodwill and long-lived assets (including oil and
natural gas properties);
|
|
|
|
Accretion of asset retirement obligations;
|
|
|
|
Unrealized losses on commodity derivative contracts;
|
|
|
|
Losses on sale of assets and other, net;
|
|
|
|
Unit-based compensation expenses;
|
|
|
|
Exploration costs; and
|
|
|
|
Other non-routine items that we deem appropriate.
|
|
|
|
|
|
Interest income;
|
|
|
|
Income tax benefit;
|
|
|
|
Unrealized gains on commodity derivative contracts;
|
|
|
|
Gains on sale of assets and other, net; and
|
|
|
|
Other non-routine items that we deem appropriate.
|
70
Memorial
Production Partners LP
Estimated Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
|
Forecasted for Twelve Months
|
|
|
|
Ending June 30, 2012
|
|
|
|
No Exercise
|
|
|
Full Exercise
|
|
|
|
of the
|
|
|
of the
|
|
|
|
Underwriters
|
|
|
Underwriters
|
|
|
|
Option to
|
|
|
Option to
|
|
|
|
Purchase
|
|
|
Purchase
|
|
|
|
Additional
|
|
|
Additional
|
|
|
|
Common Units
|
|
|
Common Units
|
|
|
|
(In millions, except for per
|
|
|
|
unit amounts)
|
|
|
Operating revenue and realized commodity derivative gains
(losses)(1)
|
|
$
|
100.7
|
|
|
$
|
100.7
|
|
Less:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
18.4
|
|
|
|
18.4
|
|
Production and ad valorem taxes
|
|
|
8.9
|
|
|
|
8.9
|
|
General and administrative expenses
|
|
|
5.0
|
|
|
|
5.0
|
|
Depreciation, depletion and amortization
|
|
|
39.0
|
|
|
|
39.0
|
|
Interest expense
|
|
|
3.8
|
|
|
|
3.8
|
|
|
|
|
|
|
|
|
|
|
Net income excluding unrealized derivative gains (losses)
|
|
$
|
25.6
|
|
|
$
|
25.6
|
|
Adjustments to reconcile net income excluding unrealized
derivative gains (losses) to estimated Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
Add:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
$
|
39.0
|
|
|
$
|
39.0
|
|
Interest expense
|
|
|
3.8
|
|
|
|
3.8
|
|
|
|
|
|
|
|
|
|
|
Estimated Adjusted EBITDA
|
|
$
|
68.4
|
|
|
$
|
68.4
|
|
Adjustments to reconcile estimated Adjusted EBITDA to cash
available for distribution:
|
|
|
|
|
|
|
|
|
Less:
|
|
|
|
|
|
|
|
|
Cash interest expense(2)
|
|
$
|
3.8
|
|
|
$
|
3.8
|
|
Estimated average maintenance capital expenditures(3)
|
|
|
9.2
|
|
|
|
9.2
|
|
|
|
|
|
|
|
|
|
|
Estimated cash available for distribution
|
|
$
|
55.4
|
|
|
$
|
55.4
|
|
Annualized minimum quarterly distribution per unit
|
|
$
|
|
|
|
$
|
|
|
Estimated annual cash distributions:
|
|
|
|
|
|
|
|
|
Distributions on common units held by purchasers in this offering
|
|
$
|
|
|
|
$
|
|
|
Distributions on common units held by Memorial Resource and its
affiliates
|
|
|
|
|
|
|
|
|
Distributions on subordinated units
|
|
|
|
|
|
|
|
|
Distributions on general partner units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total estimated annual cash distributions
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Excess cash available for distribution
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Minimum estimated Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
Estimated Adjusted EBITDA
|
|
$
|
68.4
|
|
|
$
|
68.4
|
|
Less:
|
|
|
|
|
|
|
|
|
Excess cash available for distributions(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum estimated Adjusted EBITDA
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
71
|
|
|
(1) |
|
Includes the forecasted effect of cash settlements of commodity
derivative instruments. |
|
(2) |
|
In connection with this offering, we intend to enter into a new
$ million revolving credit
facility under which we expect to incur approximately
$130.0 million of borrowings upon the closing of this
offering. If the net proceeds from this offering increase or
decrease, then our borrowing under our new revolving credit
facility would correspondingly decrease or increase,
respectively. The pro forma cash interest expense is based on
$130.0 million of borrowings at an assumed weighted-average
rate of 3.25%. If the interest rate used to calculate this
interest were 1% higher or lower, our annual cash interest
expense would increase or decrease, respectively, by
$1.2 million. Likewise, a $1.00 increase or decrease in the
assumed initial public offering price per common unit would
result in a $ million
decrease or increase in borrowings, respectively, and a
$ million decrease or
increase in interest expense, respectively. |
|
(3) |
|
In calculating the estimated cash available for distribution, we
have included our estimated maintenance capital expenditures for
the twelve months ending June 30, 2012. We expect to incur
approximately $9.2 million of capital expenditures for the
twelve months ending June 30, 2012 based on our reserve
reports as of December 31, 2010, which amount incurred
annually we also expect will enable us to maintain our targeted
average net production from our assets of 49
MMcfe/d
through December 31, 2015. |
|
(4) |
|
We intend to retain any excess cash to repay indebtedness or for
other general partnership purposes. |
Assumptions
and Considerations
Based upon the specific assumptions outlined below with respect
to the twelve months ending June 30, 2012, we expect to
generate estimated Adjusted EBITDA sufficient to establish
reserves for capital expenditures and to pay the minimum
quarterly distribution on all common, subordinated and general
partner units for the twelve months ending June 30, 2012.
While we believe that these assumptions are reasonable in light
of managements current expectations concerning future
events, the estimates underlying these assumptions are
inherently uncertain and are subject to significant business,
economic, regulatory, environmental and competitive risks and
uncertainties that could cause actual results to differ
materially from those we anticipate. If our assumptions do not
materialize, the amount of actual cash available to pay
distributions could be substantially less than the amount we
currently estimate and could, therefore, be insufficient to
permit us to pay quarterly cash distributions equal to our
minimum quarterly distribution (absent borrowings under our new
revolving credit facility), or any amount, on all common,
subordinated and general partner units, in which event the
market price of our common units may decline substantially. We
are unlikely to be able to sustain our minimum quarterly
distribution without making acquisitions or other capital
expenditures that maintain our asset base. Over a longer period
of time, if we do not set aside sufficient cash reserves or make
sufficient cash expenditures to maintain our asset base, we will
be unable to pay distributions at the then-current level from
cash generated from operations and would therefore expect to
reduce our distributions. In addition, decreases in commodity
prices from current levels will adversely affect our ability to
pay distributions. When reading this section, you should keep in
mind the risk factors and other cautionary statements described
under Risk Factors and Forward-Looking
Statements. Any of the risks discussed in this prospectus
could cause our actual results to vary significantly from our
estimates.
72
Operations
and Revenue
Production. The following table sets
forth information regarding net production of oil and natural
gas on a pro forma basis for the year ended December 31,
2010 and the twelve months ended March 31, 2011, and on a
forecasted basis for the twelve months ending June 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forecasted
|
|
|
|
Pro Forma Year
|
|
|
Pro Forma
|
|
|
Twelve Months
|
|
|
|
Ended
|
|
|
Twelve Months
|
|
|
Ending
|
|
|
|
December 31,
|
|
|
Ended
|
|
|
June 30,
|
|
|
|
2010
|
|
|
March 31, 2011
|
|
|
2012
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
|
|
Annual Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
107
|
|
|
|
106
|
|
|
|
99
|
|
NGLs (MBbl)
|
|
|
272
|
|
|
|
255
|
|
|
|
185
|
|
Natural Gas (MMcf)
|
|
|
16,713
|
|
|
|
16,447
|
|
|
|
16,185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
18,985
|
|
|
|
18,613
|
|
|
|
17,887
|
|
Average Net Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl/d)
|
|
|
0.3
|
|
|
|
0.3
|
|
|
|
0.3
|
|
NGLs (MBbl/d)
|
|
|
0.8
|
|
|
|
0.7
|
|
|
|
0.5
|
|
Natural Gas
(MMcf/d)
|
|
|
45.8
|
|
|
|
45.1
|
|
|
|
44.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe/d)
|
|
|
52.0
|
|
|
|
51.0
|
|
|
|
49.0
|
|
We estimate that our oil and natural gas production for the
twelve months ending June 30, 2012 will be
17,887 MMcfe as compared to 18,985 and 18,613 MMcfe,
respectively, on a pro forma basis for the year ended
December 31, 2010 and the twelve months ended
March 31, 2011. We intend to maintain our forecasted
production level of 49 MMcfe/d for the twelve months ending
June 30, 2012 over the long term with cash generated from
operations.
73
Prices. The table below illustrates the
relationship between average oil and natural gas realized sales
prices and the average NYMEX prices on a pro forma basis for the
year ended December 31, 2010 and the twelve months ended
March 31, 2011 and on a forecasted basis for the twelve
months ending June 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forecasted
|
|
|
|
Pro Forma
|
|
|
Pro Forma
|
|
|
Twelve Months
|
|
|
|
Year Ended
|
|
|
Twelve Months
|
|
|
Ending
|
|
|
|
December 31,
|
|
|
Ended
|
|
|
June 30,
|
|
|
|
2010
|
|
|
March 31, 2011
|
|
|
2012
|
|
|
|
(Unaudited)
|
|
|
Average oil sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX-WTI oil price per Bbl
|
|
$
|
79.59
|
|
|
$
|
83.42
|
|
|
$
|
101.16
|
|
Differential to NYMEX-WTI oil per Bbl
|
|
$
|
(5.24
|
)
|
|
$
|
(4.81
|
)
|
|
$
|
(4.25
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized oil sales price per Bbl (excluding cash settlements of
derivatives)
|
|
$
|
74.35
|
|
|
$
|
78.61
|
|
|
$
|
96.91
|
|
Realized oil sales price per Bbl (including cash settlements of
derivatives)(1)(2)
|
|
$
|
74.35
|
|
|
$
|
78.61
|
|
|
$
|
96.06
|
|
Average natural gas liquids sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX-WTI oil price per Bbl
|
|
$
|
79.59
|
|
|
$
|
83.42
|
|
|
$
|
101.16
|
|
Differential to NYMEX-WTI oil price per Bbl
|
|
$
|
(42.18
|
)
|
|
$
|
(45.54
|
)
|
|
$
|
(55.11
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized natural gas liquids sales price per Bbl (excluding cash
settlements of derivatives)(1)(2)
|
|
$
|
37.41
|
|
|
$
|
37.88
|
|
|
$
|
46.05
|
|
Realized natural gas liquids sales price per Bbl (including cash
settlements of derivatives)(1)(2)
|
|
$
|
37.41
|
|
|
$
|
37.88
|
|
|
$
|
46.05
|
|
Average natural gas sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX-Henry Hub natural gas price per MMBtu
|
|
$
|
4.39
|
|
|
$
|
4.19
|
|
|
$
|
5.03
|
|
Differential to NYMEX-Henry Hub natural gas
|
|
$
|
(0.22
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
(0.06
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized natural gas sales price per Mcf (excluding cash
settlements of derivatives)
|
|
$
|
4.17
|
|
|
$
|
3.90
|
|
|
$
|
4.97
|
|
Realized natural gas sales price per Mcf (including cash
settlements of derivatives)(1)(2)
|
|
$
|
4.17
|
|
|
$
|
3.90
|
|
|
$
|
5.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total combined price (per Mcfe, excluding cash settlements of
derivatives)
|
|
$
|
4.62
|
|
|
$
|
4.42
|
|
|
$
|
5.51
|
|
Total combined price (per Mcfe, including cash settlements of
derivatives)(1)(2)
|
|
$
|
4.62
|
|
|
$
|
4.42
|
|
|
$
|
5.63
|
|
|
|
|
(1) |
|
Average NYMEX futures prices for 2012 as reported on
June 6, 2011. For a description of the effect of lower spot
prices on cash available for distribution, please read
Sensitivity Analysis Commodity
Price Changes. |
|
(2) |
|
Our pro forma realized prices do not include gains and losses on
commodity derivative instruments. Because the commodity
derivative contracts to be contributed to us have been
commingled with the properties retained by our predecessor, the
pro forma information associated with these commodity derivative
contracts is not available by product type. We have given effect
to the expected contribution to us at the closing of this
offering of commodity derivative contracts covering 66% of our
total forecasted production for the twelve months ending
June 30, 2012. |
Price Differentials. As is typical in
the oil and natural gas industry and as reflected in our reserve
reports, we report our natural gas production and estimated
reserves in Mcf, while we sell our natural gas production and
enter into derivative contracts that measure natural gas in
MMBtu, a measure of the heating
74
capacity of natural gas. The following table presents the
average Btu content for our natural gas production by operating
area:
|
|
|
|
|
Operating Area
|
|
MMBtu per Mcf
|
|
|
South Texas
|
|
|
1.045
|
|
East Texas
|
|
|
1.027
|
|
|
|
|
|
|
Weighted Average
|
|
|
1.039
|
|
To the extent the Btu content for our natural gas production is
above 1.000 MMBtu per Mcf, we will receive a price premium
relative to the NYMEX-Henry Hub price.
However, our natural gas production has historically sold at a
negative basis differential from the NYMEX-Henry Hub price
primarily due to the distance of the production attributable to
our operating areas from the Henry Hub, which is located in
Louisiana, and other location and transportation cost factors.
In addition, our oil production, which consists of a combination
of sweet and sour oil, typically sells at a discount to the
NYMEX-WTI price due to quality and location differentials.
The adjustments we have made to reflect the basis differentials
for our forecasted production during the twelve months ending
June 30, 2012 are presented in the following table and
shown per Bbl for oil and per MMBtu as well as per Mcf for
natural gas, as reflected in our reserve reports:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
Operating Area
|
|
Per Bbl
|
|
|
Per MMBtu
|
|
|
Per Mcf
|
|
|
South Texas
|
|
$
|
(5.06
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
0.08
|
|
East Texas
|
|
$
|
(3.96
|
)
|
|
$
|
(0.43
|
)
|
|
$
|
(0.31
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
$
|
(4.25
|
)
|
|
$
|
(0.24
|
)
|
|
$
|
(0.06
|
)
|
In addition, some of our pro forma production has
transportation, gathering, and marketing charges deducted from
the prices we realize. In areas where firm transportation
capacity is contracted separately from the counterparties
purchasing the natural gas, an additional adjustment is made as
a deduction. The transportation costs are necessary to minimize
risk of flow interruption to the markets.
Use of Commodity Derivative
Contracts. At the closing of this offering,
Memorial Resource will contribute specific commodity derivative
contracts. For purposes of the forecast in this prospectus, we
have assumed that such commodity derivative contracts will cover
32 MMcfe/d, or approximately 66% of our total forecasted
production of 49 MMcfe/d for the twelve months ending
June 30, 2012. We have assumed that the assigned commodity
derivative contracts will consist of put, collar and swap
agreements for oil, NGLs and natural gas. The table below shows
the volumes, benchmark price and prices we have assumed for our
commodity derivative contracts for the twelve months ending
June 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Puts
|
|
|
Collars
|
|
|
Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Price
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Floor
|
|
|
Ceiling
|
|
|
|
|
|
Average
|
|
Oil (July 1, 2011 June 30, 2012)
|
|
Bbl
|
|
|
Price
|
|
|
Bbl
|
|
|
Price
|
|
|
Price
|
|
|
Bbl
|
|
|
Price
|
|
|
NYMEX WTI
|
|
|
3,600
|
|
|
$
|
85.00
|
|
|
|
55,800
|
|
|
$
|
86.45
|
|
|
$
|
114.34
|
|
|
|
|
|
|
|
|
|
% of forecasted oil production
|
|
|
4
|
%
|
|
|
|
|
|
|
57
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of total forecasted oil production
|
|
|
61
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Puts
|
|
|
Collars
|
|
|
Swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Price
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Floor
|
|
|
Ceiling
|
|
|
|
|
|
Average
|
|
NGL (July 1, 2011 June 30, 2012):
|
|
Bbl
|
|
|
Price
|
|
|
Bbl
|
|
|
Price
|
|
|
Price
|
|
|
Bbl
|
|
|
Price
|
|
|
Mt. Belvieu Propane
|
|
|
|
|
|
|
|
|
|
|
14,400
|
|
|
$
|
52.50
|
|
|
$
|
66.78
|
|
|
|
|
|
|
|
|
|
Mt. Belvieu Butane
|
|
|
|
|
|
|
|
|
|
|
7,200
|
|
|
$
|
71.40
|
|
|
$
|
86.10
|
|
|
|
|
|
|
|
|
|
Mt. Belvieu Isobutane
|
|
|
|
|
|
|
|
|
|
|
4,800
|
|
|
$
|
71.40
|
|
|
$
|
89.04
|
|
|
|
|
|
|
|
|
|
Mt. Belvieu Gasoline
|
|
|
|
|
|
|
|
|
|
|
19,200
|
|
|
$
|
94.50
|
|
|
$
|
117.60
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total NGL Hedges
|
|
|
|
|
|
|
|
|
|
|
45,600
|
|
|
$
|
75.16
|
|
|
$
|
93.57
|
|
|
|
|
|
|
|
|
|
% of forecasted NGL production
|
|
|
|
|
|
|
|
|
|
|
25
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of total forecasted NGL production
|
|
|
25
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Puts
|
|
|
Collars
|
|
|
Swaps
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted Average Price
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
Floor
|
|
|
Ceiling
|
|
|
|
|
|
Average
|
|
Natural Gas (July 1, 2011 June 30, 2012):
|
|
MMBtu
|
|
|
Price
|
|
|
MMBtu
|
|
|
Price
|
|
|
Price
|
|
|
MMBtu
|
|
|
Price
|
|
|
NYMEX Henry Hub
|
|
|
24,000
|
|
|
$
|
4.50
|
|
|
|
2,508,000
|
|
|
$
|
4.97
|
|
|
$
|
5.73
|
|
|
|
198,000
|
|
|
$
|
4.73
|
|
TETCO South Texas Basis
|
|
|
1,920,000
|
|
|
$
|
4.41
|
|
|
|
1,980,000
|
|
|
$
|
4.90
|
|
|
$
|
6.34
|
|
|
|
600,000
|
|
|
$
|
5.73
|
|
NGPL TexOk Basis
|
|
|
|
|
|
|
|
|
|
|
966,000
|
|
|
$
|
5.35
|
|
|
$
|
6.37
|
|
|
|
504,000
|
|
|
$
|
6.17
|
|
Houston Ship Channel Basis
|
|
|
|
|
|
|
|
|
|
|
1,500,000
|
|
|
$
|
4.27
|
|
|
$
|
5.66
|
|
|
|
960,000
|
|
|
$
|
4.84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Natural Gas Hedges
|
|
|
1,944,000
|
|
|
$
|
4.41
|
|
|
|
6,954,000
|
|
|
$
|
4.85
|
|
|
$
|
5.97
|
|
|
|
2,262,000
|
|
|
$
|
5.36
|
|
% of forecasted natural gas production
|
|
|
12
|
%
|
|
|
|
|
|
|
43
|
%
|
|
|
|
|
|
|
|
|
|
|
14
|
%
|
|
|
|
|
% of total forecasted natural gas production
|
|
|
69
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
76
Operating Revenues and Realized Commodity Derivative
Gains. The following table illustrates the
primary components of operating revenues and realized commodity
derivative gains on a pro forma basis for the year ended
December 31, 2010 and the twelve months ended
March 31, 2011 and on a forecasted basis for the twelve
months ending June 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forecasted
|
|
|
|
Pro Forma
|
|
|
Pro Forma
|
|
|
Twelve Months
|
|
|
|
Year Ended
|
|
|
Twelve Months
|
|
|
Ending
|
|
|
|
December 31,
|
|
|
Ended
|
|
|
June 30,
|
|
|
|
2010
|
|
|
March 31, 2011
|
|
|
2012
|
|
|
|
(Unaudited)
|
|
|
|
($ in millions)
|
|
|
Oil:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenues
|
|
$
|
7.9
|
|
|
$
|
8.3
|
|
|
$
|
9.6
|
|
Oil derivative contracts gain (loss)(1)
|
|
|
|
|
|
|
|
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7.9
|
|
|
$
|
8.3
|
|
|
$
|
9.5
|
|
NGLs:
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs revenues
|
|
$
|
10.2
|
|
|
$
|
9.7
|
|
|
$
|
8.5
|
|
NGLs derivative contracts gain (loss)(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10.2
|
|
|
$
|
9.7
|
|
|
$
|
8.5
|
|
Natural gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenues
|
|
$
|
69.7
|
|
|
$
|
64.2
|
|
|
$
|
80.6
|
|
Natural gas derivative contracts gain (loss)(1)
|
|
|
|
|
|
|
|
|
|
|
2.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
69.7
|
|
|
$
|
64.2
|
|
|
$
|
82.7
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
$
|
87.8
|
|
|
$
|
82.2
|
|
|
$
|
98.6
|
|
Commodity derivative contracts gain (loss)(1)
|
|
|
|
|
|
|
|
|
|
|
2.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue and realized commodity derivative contract
gains
|
|
$
|
87.8
|
|
|
$
|
82.2
|
|
|
$
|
100.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Our pro forma realized prices do not include gains or losses on
commodity derivative contracts. Because the commodity derivative
contracts to be contributed to us have been commingled with the
properties retained by our predecessor, the pro forma
information associated with these commodity derivative contracts
is not available by product type. We have given effect to the
expected contribution to us at the closing of this offering of
commodity derivative contracts covering 66% of our total
forecasted production for the twelve months ending June 30,
2012. |
Capital
Expenditures and Expenses
Capital Expenditures. Our estimated
cash reserves for maintenance capital expenditures for the
twelve months ending June 30, 2012 of $9.2 million
represents our estimate of maintenance capital expenditures
necessary to maintain our average net production of
49 MMcfe/d through December 31, 2015.
We anticipate replacing declining production and reserves
through the drilling and completing of wells on our undeveloped
properties and through the acquisition of producing and
non-producing oil and natural gas properties from Memorial
Resource and from third parties. We estimate that we will drill
5 gross (4 net) wells during the forecast period at an
aggregate net cost of approximately $6.0 million. We also
expect to spend approximately $3.2 million during the
forecast period on workovers, recompletions and other
field-related costs. Although we may make acquisitions during
the twelve months ending June 30, 2012, our forecast does
not reflect any acquisitions, as we cannot assure you that we
will be able to identify attractive properties or, if
identified, that we will be able to negotiate acceptable
purchase agreements.
77
Lease Operating Expenses. The following
table summarizes pro forma lease operating expenses on an
aggregate basis and on a per Mcfe basis for the year ended
December 31, 2010 and the twelve months ended
March 31, 2011 and forecasted lease operating expenses on
an aggregate basis and on a per Mcfe basis for the twelve months
ending June 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forecasted
|
|
|
Pro Forma
|
|
Pro Forma
|
|
Twelve Months
|
|
|
Year Ended
|
|
Twelve Months
|
|
Ending
|
|
|
December 31,
|
|
Ended
|
|
June 30,
|
|
|
2010
|
|
March 31, 2011
|
|
2012
|
|
Lease operating expenses (in millions)
|
|
$
|
23
|
.1
|
|
|
$
|
23
|
.8
|
|
|
$
|
18
|
.4
|
|
Lease operating expenses (per Mcfe)
|
|
$
|
1
|
.21
|
|
|
$
|
1
|
.28
|
|
|
$
|
1
|
.03
|
|
We estimate that our lease operating expenses for the twelve
months ending June 30, 2012 will be approximately
$18.4 million. On a pro forma basis, for the year ended
December 31, 2010 and the twelve months ended
March 31, 2011, lease operating expenses were
$23.1 million and $23.8 million, respectively, with
respect to the Partnership Properties. The decrease in
forecasted lease operating expenses is mainly a result of lower
forecasted volumes during the forecast period compared to the
pro forma year ended December 31, 2010 and the pro forma
twelve months ended March 31, 2011. Moreover, the first
quarter of 2011 contained approximately $1.0 million in
incremental workover costs associated with discovery and
production enhancements on acquired properties and other
non-recurring personnel charges. A majority of these workover
costs were initiated in January 2011 and are not expected to
continue in future periods, and the personnel charges will no
longer be charged upon consummation of this offering.
Production and Other Taxes. The
following table summarizes production and other taxes before the
effects of our commodity derivative contracts on a pro forma
basis for the year ended December 31, 2010 and the twelve
months ended March 31, 2011 and on a forecasted basis for
the twelve months ending June 30, 2012:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
Forecasted
|
|
|
Pro Forma
|
|
Twelve Months
|
|
Twelve Months
|
|
|
Year Ended
|
|
Ended
|
|
Ending
|
|
|
December 31, 2010
|
|
March 31, 2011
|
|
June 30, 2012
|
|
|
($ in millions)
|
|
Oil, natural gas and NGL revenues, excluding the effect of our
commodity derivative contracts
|
|
$
|
87.8
|
|
|
$
|
82.2
|
|
|
$
|
98.6
|
|
Production and ad valorem taxes
|
|
$
|
7.4
|
|
|
$
|
6.9
|
|
|
$
|
8.9
|
|
Production and ad valorem taxes as a percentage of revenue
|
|
|
8.4
|
%
|
|
|
8.4
|
%
|
|
|
9.0
|
%
|
Our production taxes are calculated as a percentage of our oil,
natural gas, and NGL revenues, excluding the effects of our
commodity derivative contracts. In general, as prices and
volumes increase, our production taxes increase. As prices and
volumes decrease, our production taxes decrease. Additionally,
production tax rates vary by state, and as revenues by state
vary, our production taxes will increase or decrease. Ad valorem
taxes are generally tied to the valuation of the oil and natural
gas properties; however, these valuations are reasonably
correlated to revenues, excluding the effects of our commodity
derivative contracts. As a result we are forecasting our ad
valorem taxes as a percent of revenues, excluding the effects of
our commodity derivative contracts.
General and Administrative Expenses. We
estimate that general and administrative expense for the twelve
months ending June 30, 2012 will be $5.0 million as
compared to $5.8 million and $6.2 million on a pro
forma basis for the year ending December 31, 2010 and the
twelve months ending March 31, 2011, respectively,
substantially all of which will be reimbursable to Memorial
Resource for services performed on our behalf pursuant to the
omnibus agreement. We estimate that the $2.5 million
increase in general and administrative expense associated with
being a publicly traded partnership will be offset by the
expected synergies associated with the combination of the
Partnership Properties.
78
Depreciation, Depletion and Amortization
Expense. We estimate that our depreciation,
depletion and amortization expense for the twelve months ending
June 30, 2012 will be approximately $39.0 million, as
compared to $34.8 million and $32.7 million on a pro
forma basis for the year ending December 31, 2010 and the
twelve months ended March 31, 2011, respectively. The
forecasted depletion of our oil and natural gas properties is
based on the production estimates in our reserve reports. Our
capitalized costs are calculated using the successful efforts
accounting method. For a detailed description of the successful
efforts method of accounting, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Critical
Accounting Policies and Estimates.
Cash Interest Expense. We estimate that
at the closing of this offering we will borrow approximately
$130.0 million in revolving debt under our new
$ million revolving credit
facility. We estimate that the borrowings will bear interest at
a weighted average rate of approximately 3.25%. Based on these
assumptions, we estimate that our cash interest expense for the
twelve months ending June 30, 2012 will be
$3.8 million as compared to $4.0 million and
$4.0 million, respectively, on a pro forma basis for the
year ended December 31, 2010 and the twelve months ended
March 31, 2011.
We expect that our new revolving credit facility will contain
financial covenants that require us to maintain a leverage ratio
of not more
than to
1.0x and a current ratio of not less
than to
1.0x. Please read Managements Discussion and
Analysis of Financial Condition and Results of
Operations Pro Forma Liquidity and Capital
Resources New Revolving Credit Facility for
additional detail regarding the covenants and restrictive
provisions to be included in our new revolving credit facility.
We expect that the new revolving credit facility will not
require any cash expenditures on our part other than cash
interest expense that would affect our cash available for
distribution. As a result, based on the assumptions used in
preparing the estimates set forth above, the new revolving
credit facility, including the financial covenants and borrowing
base utilization limitation discussed above, will not have any
effect upon our ability to pay the estimated distributions to
our unitholders during the forecast period.
Regulatory,
Industry and Economic Factors
Our forecast for the twelve months ending June 30, 2012 is
based on the following significant assumptions related to
regulatory, industry and economic factors:
|
|
|
|
|
There will not be any new federal, state or local regulation of
portions of the energy industry in which we operate, or an
interpretation of existing regulation, that will be materially
adverse to our business;
|
|
|
|
There will not be any major adverse change in commodity prices
or the energy industry in general;
|
|
|
|
Market, insurance and overall economic conditions will not
change substantially; and
|
|
|
|
We will not undertake any extraordinary transactions that would
materially affect our cash flow.
|
Forecasted
Distributions
We expect that aggregate quarterly distributions of available
cash on our common units, subordinated units and general partner
units for the twelve months ending June 30, 2012 will be
approximately $ million.
Quarterly distributions of available cash will be paid within
45 days after the close of each calendar quarter.
While we believe that the assumptions we have used in preparing
the estimates set forth above are reasonable based upon
managements current expectations concerning future events,
they are inherently uncertain and are subject to significant
business, economic regulatory and competitive risks and
uncertainties, including those described in Risk
Factors, that could cause actual results to differ
materially from those we anticipate. If our assumptions are not
realized, the actual available cash that we generate could be
substantially less than the amount we currently estimate and
could, therefore, be insufficient to permit us to pay the full
minimum quarterly distribution or any amount on all our
outstanding common, subordinated and general partner units in
respect of the four calendar quarters ending June 30, 2012
or thereafter, in which event the market price of the common
units may decline materially.
79
Sensitivity
Analysis
Our ability to generate sufficient cash from operations to pay
distributions to our unitholders is a function of two primary
variables: (i) production volumes and (ii) commodity
prices. In the paragraphs below, we discuss the impact that
changes in either of these variables, while holding all other
variables constant, would have on our ability to generate
sufficient cash from our operations to pay the minimum quarterly
distributions on our outstanding common units, general partner
units and subordinated units for the twelve months ending
June 30, 2012.
Production
Volume Changes
The following table shows estimated Adjusted EBITDA under
production levels of 90%, 100% and 110% of the production level
we have forecasted for the twelve months ending June 30,
2012. The estimated Adjusted EBITDA amounts shown below are
based on the assumptions used in our forecast.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Forecasted Net Production
|
|
|
|
90%
|
|
|
100%
|
|
|
110%
|
|
|
|
(In millions, except per unit amounts)
|
|
|
Forecasted net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
88.8
|
|
|
|
98.7
|
|
|
|
108.5
|
|
NGLs (MBbl)
|
|
|
166.4
|
|
|
|
184.9
|
|
|
|
203.4
|
|
Natural gas (MMcf)
|
|
|
14,566.8
|
|
|
|
16,185.4
|
|
|
|
17,803.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
16,098.2
|
|
|
|
17,886.9
|
|
|
|
19,675.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbl/d)
|
|
|
242.6
|
|
|
|
269.6
|
|
|
|
296.5
|
|
NGLs (Bbl/d)
|
|
|
454.7
|
|
|
|
505.3
|
|
|
|
555.8
|
|
Natural gas (Mcf/d)
|
|
|
39,800.1
|
|
|
|
44,222.3
|
|
|
|
48,644.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfe/d)
|
|
|
43,984.3
|
|
|
|
48,871.4
|
|
|
|
53,758.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forecasted prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX-WTI oil price (per Bbl)
|
|
$
|
101.16
|
|
|
$
|
101.16
|
|
|
$
|
101.16
|
|
Realized oil price (per Bbl) (excluding derivatives)
|
|
$
|
96.91
|
|
|
$
|
96.91
|
|
|
$
|
96.91
|
|
Realized oil price (per Bbl) (including derivatives)
|
|
$
|
95.96
|
|
|
$
|
96.06
|
|
|
$
|
96.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX-WTI oil price (per Bbl)
|
|
$
|
101.16
|
|
|
$
|
101.16
|
|
|
$
|
101.16
|
|
Realized natural gas liquids price (per Bbl) (excluding
derivatives)
|
|
$
|
46.05
|
|
|
$
|
46.05
|
|
|
$
|
46.05
|
|
Realized natural gas liquids price (per Bbl) (including
derivatives)
|
|
$
|
46.05
|
|
|
$
|
46.05
|
|
|
$
|
46.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX-Henry Hub natural gas price (per MMBtu)
|
|
$
|
5.03
|
|
|
$
|
5.03
|
|
|
$
|
5.03
|
|
Realized natural gas price (per Mcf) (excluding derivatives)
|
|
$
|
4.97
|
|
|
$
|
4.97
|
|
|
$
|
4.97
|
|
Realized natural gas price (per Mcf) (including derivatives)
|
|
$
|
5.13
|
|
|
$
|
5.11
|
|
|
$
|
5.10
|
|
80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of Forecasted Net Production
|
|
|
|
90%
|
|
|
100%
|
|
|
110%
|
|
|
|
(In millions, except per unit amounts)
|
|
|
Forecasted Adjusted EBITDA projection:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
88.8
|
|
|
$
|
98.6
|
|
|
$
|
108.5
|
|
Realized derivative gains (losses)
|
|
|
2.1
|
|
|
|
2.1
|
|
|
|
2.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue and realized derivative gains (losses)
|
|
$
|
90.9
|
|
|
$
|
100.7
|
|
|
$
|
110.6
|
|
Oil and natural gas production expenses
|
|
|
(16.6
|
)
|
|
|
(18.4
|
)
|
|
|
(20.3
|
)
|
Production and ad valorem taxes
|
|
|
(8.2
|
)
|
|
|
(8.9
|
)
|
|
|
(9.6
|
)
|
General and administrative expenses
|
|
|
(5.0
|
)
|
|
|
(5.0
|
)
|
|
|
(5.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Adjusted EBITDA
|
|
$
|
61.1
|
|
|
$
|
68.4
|
|
|
$
|
75.7
|
|
Minimum estimated Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess cash available for distribution
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Commodity
Price Changes
The following table shows estimated Adjusted EBITDA under
various assumed NYMEX-WTI oil and natural gas prices for the
twelve months ending June 30, 2012. For purposes of this
prospectus, we have assumed that, at the closing of this
offering, Memorial Resource will contribute specific commodity
derivative contracts covering 32 MMcfe/d, or approximately
66% of our total forecasted production of 49 MMcfe/d for
the twelve months ending June 30, 2012. In addition, the
estimated Adjusted EBITDA amounts shown below
81
are based on forecasted realized commodity prices that take into
account our average NYMEX commodity price differential
assumptions. We have assumed no changes in our production based
on changes in prices.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions of dollars, except per unit amounts)
|
|
|
NYMEX-Henry Hub natural gas price (per MMBtu):
|
|
$
|
4.75
|
|
|
$
|
5.00
|
|
|
$
|
5.25
|
|
|
$
|
5.50
|
|
NYMEX-WTI oil price (per Bbl):
|
|
$
|
90.00
|
|
|
$
|
100.00
|
|
|
$
|
110.00
|
|
|
$
|
120.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forecasted net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbl)
|
|
|
98.7
|
|
|
|
98.7
|
|
|
|
98.7
|
|
|
|
98.7
|
|
NGLs (MBbl)
|
|
|
184.9
|
|
|
|
184.9
|
|
|
|
184.9
|
|
|
|
184.9
|
|
Natural gas (MMcf)
|
|
|
16,185.4
|
|
|
|
16,185.4
|
|
|
|
16,185.4
|
|
|
|
16,185.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
17,886.9
|
|
|
|
17,886.9
|
|
|
|
17,886.9
|
|
|
|
17,886.9
|
|
Oil (Bbl/d)
|
|
|
269.6
|
|
|
|
269.6
|
|
|
|
269.6
|
|
|
|
269.6
|
|
NGLs (Bbl/d)
|
|
|
505.3
|
|
|
|
505.3
|
|
|
|
505.3
|
|
|
|
505.3
|
|
Natural gas (Mcf/d)
|
|
|
44,222.3
|
|
|
|
44,222.3
|
|
|
|
44,222.3
|
|
|
|
44,222.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (Mcfe/d)
|
|
|
48,871.4
|
|
|
|
48,871.4
|
|
|
|
48,871.4
|
|
|
|
48,871.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forecasted prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX-WTI oil price (per Bbl)
|
|
$
|
90.00
|
|
|
$
|
100.00
|
|
|
$
|
110.00
|
|
|
$
|
120.00
|
|
Realized oil price (per Bbl) (excluding derivatives)
|
|
$
|
85.75
|
|
|
$
|
95.75
|
|
|
$
|
105.75
|
|
|
$
|
115.75
|
|
Realized oil price (per Bbl) (including derivatives)
|
|
$
|
85.68
|
|
|
$
|
95.03
|
|
|
$
|
103.76
|
|
|
$
|
111.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX-WTI oil price (per Bbl)
|
|
$
|
90.00
|
|
|
$
|
100.00
|
|
|
$
|
110.00
|
|
|
$
|
120.00
|
|
Realized natural gas liquids price (per Bbl) (excluding
derivatives)
|
|
$
|
40.97
|
|
|
$
|
45.52
|
|
|
$
|
50.07
|
|
|
$
|
54.62
|
|
Realized natural gas liquids price (per Bbl) (including
derivatives)
|
|
$
|
41.35
|
|
|
$
|
45.52
|
|
|
$
|
49.85
|
|
|
$
|
53.01
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX-Henry Hub natural gas price (per MMBtu)
|
|
$
|
4.75
|
|
|
$
|
5.00
|
|
|
$
|
5.25
|
|
|
$
|
5.50
|
|
Realized natural gas price (per Mcf) (excluding derivatives)
|
|
$
|
4.70
|
|
|
$
|
4.94
|
|
|
$
|
5.19
|
|
|
$
|
5.44
|
|
Realized natural gas price (per Mcf) (including derivatives)
|
|
$
|
4.94
|
|
|
$
|
5.08
|
|
|
$
|
5.26
|
|
|
$
|
5.44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forecasted Adjusted EBITDA projection:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
92.1
|
|
|
$
|
97.9
|
|
|
$
|
103.7
|
|
|
$
|
109.6
|
|
Realized derivative gains (losses)
|
|
|
4.0
|
|
|
|
2.0
|
|
|
|
0.9
|
|
|
|
(0.6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue and realized derivative gains (losses)
|
|
$
|
96.0
|
|
|
$
|
99.9
|
|
|
$
|
104.6
|
|
|
$
|
108.9
|
|
Oil and natural gas production expenses
|
|
|
(18.4
|
)
|
|
|
(18.4
|
)
|
|
|
(18.4
|
)
|
|
|
(18.4
|
)
|
Production and ad valorem taxes
|
|
|
(8.4
|
)
|
|
|
(8.8
|
)
|
|
|
(9.2
|
)
|
|
|
(9.6
|
)
|
General and administrative expenses
|
|
|
(5.0
|
)
|
|
|
(5.0
|
)
|
|
|
(5.0
|
)
|
|
|
(5.0
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Adjusted EBITDA
|
|
$
|
64.2
|
|
|
$
|
67.7
|
|
|
$
|
71.9
|
|
|
$
|
75.9
|
|
Minimum estimated Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess cash available for distribution
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
We expect to adopt a hedging policy designed to reduce the
impact to our cash flows from commodity price volatility. Under
this policy, we intend to enter into commodity derivative
contracts covering approximately 65% to 85% of our estimated
production from total proved developed producing reserves over a
three-to-five
year period at any given point in time. We may, however, from
time to time hedge more or less than this approximate range. As
opposed to entering into commodity derivative contracts at
predetermined times or on prescribed terms, we intend to enter
into commodity derivative contracts in connection with material
increases in our estimated reserves and at times when we believe
market conditions or other
82
circumstances suggest that it is prudent to do so. By removing a
significant portion of price volatility associated with
production, we believe we will mitigate, but not eliminate, the
potential negative effects of reductions in commodity prices on
our cash flow from operations for those periods. However, our
hedging activity may also reduce our ability to benefit from
increases in commodity prices. Additionally, we intend to
individually identify these non-speculative hedges as
designated hedges for U.S. federal income tax
purposes as we enter into them.
As NYMEX oil and natural gas prices decline, our estimated
Adjusted EBITDA does not decline proportionately for two
reasons: (1) the effects of our commodity derivative
contracts and (2) the effects of our general and
administrative expenses, which are not expected to correlate
with oil and natural gas prices. Furthermore, we have assumed no
changes in estimated production or oil and natural gas operating
costs during the twelve months ending June 30, 2012.
However, over the long term, a sustained decline in oil and
natural gas prices would likely lead to a decline in production
and oil and natural gas operating costs as well as a reduction
in our realized oil and natural gas prices. Therefore, the
foregoing table is not illustrative of all of the potential
effects of changes in commodity prices for periods subsequent to
June 30, 2012.
83
PROVISIONS
OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH
DISTRIBUTIONS
Set forth below is a summary of the significant provisions of
our partnership agreement that relate to cash distributions.
Distributions
of Available Cash
General
Our partnership agreement requires that, within 45 days
after the end of each quarter, beginning with the quarter
ending ,
2011, we distribute all of our available cash to unitholders of
record on the applicable record date. We will adjust the minimum
quarterly distribution payable in respect of the quarter
ending ,
2011 for the period from the closing of the offering
through ,
2011.
Definition
of Available Cash
Available cash, for any quarter, consists of all cash and cash
equivalents on hand at the end of that quarter:
|
|
|
|
|
less, the amount of cash reserves established by our general
partner at the date of determination of available cash for the
quarter to:
|
|
|
|
|
|
provide for the proper conduct of our business, which could
include, but is not limited to, amounts reserved for capital
expenditures, working capital and operating expenses;
|
|
|
|
comply with applicable law, any of our debt instruments or other
agreements; or
|
|
|
|
provide funds for distributions to our unitholders (including
our general partner) for any one or more of the next four
quarters (provided that our general partner may not establish
cash reserves for future distributions on our common and
subordinated units unless it determines that the establishment
of reserves will not prevent us from distributing the minimum
quarterly distribution on all common units and any cumulative
arrearages on such common units for such quarter);
|
|
|
|
|
|
plus, if our general partner so determines, all or a portion of
cash on hand on the date of determination of available cash for
the quarter resulting from borrowing (including working capital
borrowings) made after the end of the quarter.
|
The purpose and effect of the last bullet point above is to
allow our general partner, if it so decides, to use cash from
borrowing (including working capital borrowings) made after the
end of the quarter but on or before the date of determination of
available cash for that quarter to pay distributions to
unitholders.
Working capital borrowings are borrowings that are made under a
credit facility, commercial paper facility or similar financing
arrangement, and in all cases are used solely for working
capital purposes or to pay distributions to partners and with
the intent of the borrower to repay such borrowings within
twelve months from sources other than additional working capital
borrowings.
Intent
to Distribute the Minimum Quarterly Distribution
We intend to distribute to the holders of common and
subordinated units on a quarterly basis at least the minimum
quarterly distribution of $ per
unit, or $ per unit on an
annualized basis, to the extent we have sufficient cash from our
operations after the establishment of cash reserves and payment
of fees and expenses, including payments (or reserving for
payment) of fees and expenses to our general partner and its
affiliates. However, there is no guarantee that we will pay the
minimum quarterly distribution on the units in any quarter. Even
if our cash distribution policy is not modified or revoked, the
amount of distributions paid under our policy and the decision
to make any distribution is determined by our general partner,
taking into consideration the terms of our partnership agreement.
84
General
Partner Interest and Incentive Distribution Rights
Initially, our general partner will be entitled to 0.1% of all
quarterly distributions that we make prior to our liquidation.
Our general partners 0.1% interest in us is represented by
general partner units for allocation and distribution purposes.
At the consummation of this offering, our general partners
0.1% interest in us will be represented
by
general partner units (or general partner units if the
underwriters exercise their option to purchase additional common
units in full). Our general partner has the right, but not the
obligation, to contribute a proportionate amount of capital to
us in exchange for additional general partner units to maintain
its current general partner interest. Our general partners
initial 0.1% interest in our distributions will be reduced if we
issue additional limited partner units in the future (other than
the issuance of common units upon exercise by the underwriters
of their option to purchase additional common units, the
issuance of common units to Memorial Resource upon expiration of
the underwriters option to purchase additional common
units, or the issuance of common units upon conversion of
outstanding subordinated units) and our general partner does not
contribute a proportionate amount of capital to us in exchange
for additional general partner units to maintain its 0.1%
general partner interest.
Our general partner also holds incentive distribution rights
that entitle it to receive increasing percentages, up to a
maximum of 25.0%, of the cash we distribute from operating
surplus (as defined below) in excess of
$ per unit per quarter. The
maximum distribution of 25.0% includes distributions paid to our
general partner on its 0.1% general partner interest and assumes
that our general partner maintains its general partner interest
at 0.1%. The maximum distribution of 25.0% does not include any
distributions that our general partner may receive on common
units or subordinated units that it owns. Upon the closing of
this offering, the Funds will hold non-voting member interests
in our general partner that entitle them collectively to 50.0%
of all cash distributions received by our general partner in
respect of the incentive distribution rights and any common
units issued to our general partner in connection with a reset
of the incentive distribution rights. Please read
General Partner Interest and Incentive
Distribution Rights.
Operating
Surplus and Capital Surplus
General
All cash distributed to unitholders will be characterized as
either operating surplus or capital
surplus. Our partnership agreement requires that we
distribute available cash from operating surplus differently
than available cash from capital surplus.
Operating
Surplus
Our partnership agreement requires that we distribute available
cash from operating surplus differently than available cash from
capital surplus. Operating surplus for any period consists of:
|
|
|
|
|
$ million (as described
below); plus
|
|
|
|
all of our cash receipts after the closing of this offering,
excluding cash from interim capital transactions, which include
the following:
|
|
|
|
|
|
borrowings (including sales of debt securities) that are not
working capital borrowings;
|
|
|
|
sales of equity interests; and
|
|
|
|
sales or other dispositions of assets outside the ordinary
course of business;
|
provided that cash receipts from the termination of a commodity
hedge or interest rate hedge prior to its specified termination
date shall be included in operating surplus in equal quarterly
installments over the remaining scheduled life of such commodity
hedge or interest rate hedge; plus
|
|
|
|
|
working capital borrowings made after the end of the period but
on or before the date of determination of operating surplus for
the period; plus
|
85
|
|
|
|
|
cash distributions paid (including incremental incentive
distributions) on equity issued to finance all or a portion of
the construction, replacement, acquisition, development or
improvement of a capital improvement or replacement of a capital
asset (such as reserves or equipment) in respect of the period
beginning on the date that we enter into a binding obligation to
commence the construction, replacement, acquisition, development
or improvement of a capital improvement, construction,
replacement, acquisition, development or improvement of a
capital asset and ending on the earlier to occur of the date the
capital improvement or capital asset begins producing in paying
quantities or is placed into service, as applicable, and the
date that it is abandoned or disposed of; plus
|
|
|
|
cash distributions paid (including incremental incentive
distributions) on equity issued to pay the construction period
interest on debt incurred (including periodic net payments under
related interest rate swap arrangements), or to pay construction
period distributions on equity issued, to finance the capital
improvements or capital assets referred to above; less
|
|
|
|
all of our operating expenditures (as described below) after the
closing of this offering and the completion of the formation
transactions; less
|
|
|
|
the amount of cash reserves established by our general partner
to provide funds for future operating expenditures; less
|
|
|
|
all working capital borrowings not repaid within twelve months
after having been incurred, or repaid within such twelve month
period with the proceeds of additional working capital
borrowings; less
|
|
|
|
any cash loss realized on disposition of an investment capital
expenditure.
|
As described above, operating surplus does not reflect actual
cash on hand that is available for distribution to our
unitholders and is not limited to cash generated by our
operations. For example, it includes a basket of
$ million that will enable
us, if we choose, to distribute as operating surplus cash we
receive in the future from non-operating sources such as asset
sales, issuances of securities and long-term borrowings that
would otherwise be distributed as capital surplus. In addition,
the effect of including (as described above) certain cash
distributions on equity interests in operating surplus will be
to increase operating surplus by the amount of any such cash
distributions. As a result, we may also distribute as operating
surplus up to the amount of any such cash that we receive from
non-operating sources.
The proceeds of working capital borrowings increase operating
surplus and repayments of working capital borrowings are
generally operating expenditures (as described below) and thus
reduce operating surplus when repayments are made. However, if a
working capital borrowing is not repaid during the twelve-month
period following the borrowing, it will be deemed repaid at the
end of such period, thus decreasing operating surplus at such
time. When such working capital borrowing is in fact repaid, it
will be excluded from operating expenditures because operating
surplus will have been previously reduced by the deemed
repayment.
We define operating expenditures in our partnership agreement,
and it generally means all of our cash expenditures, including,
but not limited to, taxes, reimbursement for expenses of our
general partner and its affiliates, payments made in the
ordinary course of business under interest rate and commodity
hedge contracts, (provided that (i) with respect to amounts
paid in connection with the initial purchase of an interest rate
hedge contract or a commodity hedge contract, such amounts will
be amortized over the life of the applicable interest rate hedge
contract or commodity hedge contract and (ii) payments made
in connection with the termination of any interest rate hedge
contract or commodity hedge contract prior to the expiration of
its stipulated settlement or termination date will be included
in operating expenditures in equal quarterly installments over
the remaining scheduled life of such interest rate hedge
contract or commodity hedge contract), officer compensation,
repayment of working capital borrowings, debt service payments
(except as otherwise provided in our partnership agreement) and
estimated maintenance capital expenditures (as discussed in
further detail below), provided that operating expenditures will
not include:
|
|
|
|
|
repayment of working capital borrowings previously deducted from
operating surplus pursuant to the provision described in the
penultimate bullet point of the description of operating surplus
above when such repayment actually occurs;
|
86
|
|
|
|
|
payments (including prepayments and prepayment penalties) of
principal of and premium on indebtedness, other than working
capital borrowings;
|
|
|
|
growth capital expenditures;
|
|
|
|
actual maintenance capital expenditures (as discussed in further
detail below);
|
|
|
|
investment capital expenditures;
|
|
|
|
payment of transaction expenses relating to interim capital
transactions;
|
|
|
|
distributions to our partners; or
|
|
|
|
repurchases of equity interests except to fund obligations under
employee benefit plans.
|
Capital
Surplus
Capital surplus is defined in our partnership agreement as any
distribution of available cash in excess of our cumulative
operating surplus. Accordingly, capital surplus would generally
be generated by:
|
|
|
|
|
borrowings (including sales of debt securities) other than
working capital borrowings;
|
|
|
|
sales of our equity interests; and
|
|
|
|
sales or other dispositions of assets outside the ordinary
course of business.
|
Characterization
of Cash Distributions
Our partnership agreement requires that we treat all available
cash distributed as coming from operating surplus until the sum
of all available cash distributed since the closing of this
offering equals the operating surplus from the closing of this
offering through the end of the quarter immediately preceding
that distribution. Our partnership agreement requires that we
treat any amount distributed in excess of operating surplus,
regardless of its source, as capital surplus. We do not
anticipate that we will make any distributions from capital
surplus.
Capital
Expenditures
Estimated maintenance capital expenditures reduce operating
surplus, but growth capital expenditures, actual maintenance
capital expenditures and investment capital expenditures do not.
Maintenance capital expenditures are those capital expenditures
required to maintain our asset base over the long term. We
expect that a primary component of maintenance capital
expenditures will be capital expenditures associated with the
replacement of equipment and oil and natural gas reserves
(including non-proved reserves attributable to undeveloped
leasehold acreage), whether through the development,
exploitation and production of an existing leasehold or the
acquisition or development of a new oil and natural gas
property. Maintenance capital expenditures will also include
interest (and related fees) on debt incurred and distributions
on equity issued (including incremental distributions on
incentive distribution rights) to finance all or any portion of
any replacement asset that is paid in respect of the period from
such financing until the earlier to occur of the date that any
such construction, replacement, acquisition or improvement of a
capital improvement or construction replacement, acquisition or
improvement of a capital asset begins producing in paying
quantities or is placed into service, as applicable, and the
date that it is abandoned or disposed of. Plugging and
abandonment cost will also constitute maintenance capital
expenditures. Capital expenditures made solely for investment
purposes will not be considered maintenance capital expenditures.
Because our maintenance capital expenditures can be irregular,
the amount of our actual maintenance capital expenditures may
differ substantially from period to period, which could cause
similar fluctuations in the amounts of operating surplus and
adjusted operating surplus if we subtracted actual maintenance
capital expenditures from operating surplus. To address this
issue, our partnership agreement will require that an estimate
of the average quarterly maintenance capital expenditures
(including estimated plugging and abandonment costs) necessary
to maintain our asset base over the long term be subtracted from
operating
87
surplus each quarter as opposed to the actual amounts spent. The
amount of estimated maintenance capital expenditures deducted
from operating surplus is subject to review and change by our
general partners board of directors at least once a year,
provided that any change is approved by the conflicts committee
of our general partners board of directors. The estimate
will be made at least annually and whenever an event occurs that
is likely to result in a material adjustment to the amount of
our maintenance capital expenditures, such as a major
acquisition or the introduction of new governmental regulations
that will impact our business. For purposes of calculating
operating surplus, any adjustment to this estimate will be
prospective only. For a discussion of the amounts we have
allocated toward estimated maintenance capital expenditures,
please read Our Cash Distribution Policy and Restrictions
on Distributions.
The use of estimated maintenance capital expenditures in
calculating operating surplus will have the following effects:
|
|
|
|
|
it will reduce the risk that maintenance capital expenditures in
any one quarter will be large enough to render operating surplus
less than the minimum quarterly distribution to be paid on all
the units for the quarter;
|
|
|
|
it will increase our ability to distribute as operating surplus
cash we receive from non-operating sources;
|
|
|
|
in quarters where estimated maintenance capital expenditures
exceed actual maintenance capital expenditures, it will be more
difficult for us to raise our distribution above the minimum
quarterly distribution, because the amount of estimated
maintenance capital expenditures will reduce the amount of cash
available for distribution to our unitholders, even in quarters
where there are no corresponding actual capital expenditures;
conversely, the use of estimated maintenance capital
expenditures in calculating operating surplus will have the
opposite effect for quarters in which actual maintenance capital
expenditures exceed our estimated maintenance capital
expenditures; and
|
|
|
|
it will reduce the likelihood that a large maintenance capital
expenditure during a particular quarter will prevent our general
partners affiliates from being able to convert some or all
of their subordinated units to common units since the effect of
an estimate is to spread the expected expense over several
periods, thereby mitigating the effect of the actual payment of
the expenditure on any single period.
|
Growth capital expenditures are those capital expenditures that
we expect will increase our asset base over the long term.
Examples of growth capital expenditures include the acquisition
of reserves or equipment, the acquisition of new leasehold
interest, or the development, exploitation and production of an
existing leasehold interest, to the extent such expenditures are
incurred to increase our asset base over the long term. Growth
capital expenditures will also include interest (and related
fees) on debt incurred and distributions on equity issued
(including incremental distributions on incentive distribution
rights) to finance all or any portion of such capital
improvement during the period from such financing until the
earlier to occur of the date any such capital improvement begins
producing in paying quantities or is placed into service, as
applicable, or the date that it is abandoned or disposed of.
Capital expenditures made solely for investment purposes will
not be considered growth capital expenditures.
Investment capital expenditures are those capital expenditures
that are neither maintenance capital expenditures nor growth
capital expenditures. Investment capital expenditures largely
will consist of capital expenditures made for investment
purposes. Examples of investment capital expenditures include
traditional capital expenditures for investment purposes, such
as purchases of securities, as well as other capital
expenditures that might be made in lieu of such traditional
investment capital expenditures, such as the acquisition of a
capital asset for investment purposes or development of our
undeveloped properties in excess of the maintenance of our asset
base, but which are not expected to expand our asset base for
more than the short term.
As described above, neither investment capital expenditures nor
growth capital expenditures will be included in operating
expenditures, and thus will not reduce operating surplus.
Because growth capital expenditures include interest payments
(and related fees) on debt incurred to finance all or a portion
of the construction, replacement or improvement of a capital
asset (such as equipment or reserves) during the period
88
from such financing until the earlier to occur of the date any
such capital asset begins producing in paying quantities or is
placed into service, as applicable, and the date that it is
abandoned or disposed of, such interest payments also do not
reduce operating surplus. Losses on disposition of an investment
capital expenditure will reduce operating surplus when realized
and cash receipts from an investment capital expenditure will be
treated as a cash receipt for purposes of calculating operating
surplus only to the extent the cash receipt is a return on
principal.
Capital expenditures that are made in part for maintenance
capital purposes and in part for investment capital or growth
capital purposes will be allocated as maintenance capital
expenditures, investment capital expenditures or growth capital
expenditure by our general partners board of directors,
based upon its good faith determination, subject to approval by
the conflicts committee of our general partners board of
directors.
Subordination
Period
General
Our partnership agreement provides that, during the
subordination period (which we describe below), the common
units, will have the right to receive distributions of available
cash from operating surplus each quarter in an amount equal to
$ per common unit, which amount is
defined in our partnership agreement as the minimum quarterly
distribution, plus any arrearages in the payment of the minimum
quarterly distribution on the common units from prior quarters,
before any distributions of available cash from operating
surplus may be made on the subordinated units. These units are
deemed subordinated because for a period of time,
referred to as the subordination period, the subordinated units
will not be entitled to receive any distributions from operating
surplus until the common units, have received the minimum
quarterly distribution plus any arrearages from prior quarters.
Furthermore, no arrearages will be paid on the subordinated
units. The practical effect of the subordinated units is to
increase the likelihood that during the subordination period
there will be available cash from operating surplus to be
distributed on the common units.
Expiration
of the Subordination Period
Except as described below under Early
Conversion of Subordinated Units, the subordination period
will extend until the first day of any quarter beginning
after ,
2014 that each of the following tests are met:
|
|
|
|
|
distributions of available cash from operating surplus on each
of the outstanding common units, subordinated units, and general
partner units equaled or exceeded, in the aggregate, the minimum
quarterly distributions payable with respect to a period of
twelve consecutive quarters immediately preceding that date;
|
|
|
|
the adjusted operating surplus (as defined below)
generated during the twelve consecutive quarters immediately
preceding that date equaled or exceeded, in the aggregate, the
sum of the minimum quarterly distributions on all of the
outstanding common units, subordinated units, and general
partner units payable with respect to such period on a fully
diluted basis; and
|
|
|
|
there are no arrearages in payment of the minimum quarterly
distribution on the common units.
|
Early
Conversion of Subordinated Units
The subordination period will automatically terminate, and all
of the subordinated units will convert into an equal number of
common units, on the first business day after the distribution
to unitholders in respect of any quarter beginning with the
quarter ending on or
after ,
2012, if the following tests are met:
|
|
|
|
|
distributions of available cash from operating surplus on each
of the outstanding common units, subordinated units and the
general partner units equaled or exceeded
$ (125% of the minimum quarterly
distribution), and the related distribution on the incentive
distribution rights was made, for the four-quarter period
immediately preceding that date;
|
89
|
|
|
|
|
the adjusted operating surplus generated during the
four-quarter period immediately preceding that date equaled or
exceeded the sum of a distribution of
$ (125% of the minimum quarterly
distribution) on all of the outstanding common units and
subordinated units on a fully diluted basis and the related
distributions on the general partner units and the incentive
distribution rights during those periods; and
|
|
|
|
there are no arrearages in payment of the minimum quarterly
distribution on the common units.
|
Effect
of the Expiration of the Subordination Period
When the subordination period ends, each outstanding
subordinated unit will convert into one common unit and will
then participate pro rata with the other common units in
distributions of available cash. Common units will then no
longer be entitled to arrearages.
Effect
of the Expiration of the Subordination Period Following Removal
of our General Partner
If the unitholders remove our general partner other than for
cause and no units held by the holders of the subordinated units
or their affiliates are voted in favor of such removal:
|
|
|
|
|
the subordination period will end and each subordinated unit
will immediately convert into one common unit;
|
|
|
|
any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
|
|
|
|
our general partner will have the right to convert its general
partner units into common units or to receive cash in exchange
for such general partner units at the equivalent common unit
fair market value.
|
Adjusted
Operating Surplus
Adjusted operating surplus is intended to reflect the cash
generated from operations during a particular period and
therefore excludes net increases in working capital borrowings
and net drawdowns of reserves of cash generated in prior
periods. Adjusted operating surplus for any period consists of:
|
|
|
|
|
operating surplus generated with respect to that period
(excluding any amounts attributable to the items described in
the first bullet point under Operating Surplus
and Capital Surplus Operating Surplus);
less
|
|
|
|
any net increase in working capital borrowings with respect to
that period; less
|
|
|
|
any net decrease in cash reserves for operating expenditures
with respect to that period not relating to an operating
expenditure made with respect to that period; plus
|
|
|
|
any net decrease in working capital borrowings with respect to
that period; plus
|
|
|
|
any net increase in cash reserves for operating expenditures
with respect to that period required by any debt instrument for
the repayment of principal, interest or premium; plus
|
|
|
|
any net decrease made in subsequent periods in cash reserves for
operating expenditures initially established with respect to
such period to the extent such decrease results in a reduction
of adjusted operating surplus in subsequent periods pursuant to
the third bullet point above.
|
90
Distributions
of Available Cash from Operating Surplus During the
Subordination Period
Our partnership agreement requires that we make distributions of
available cash from operating surplus for any quarter during the
subordination period in the following manner:
|
|
|
|
|
first, 99.9% to the common unitholders, pro rata, and
0.1% to our general partner, until we distribute for each
outstanding common unit an amount equal to the minimum quarterly
distribution for that quarter;
|
|
|
|
second, 99.9% to the common unitholders, pro rata, and
0.1% to our general partner, until we distribute for each
outstanding common unit an amount equal to any arrearages in
payment of the minimum quarterly distribution on the common
units for any prior quarters during the subordination period;
|
|
|
|
third, 99.9% to the subordinated unitholders, pro rata,
and 0.1% to our general partner, until we distribute for each
subordinated unit an amount equal to the minimum quarterly
distribution for that quarter; and
|
|
|
|
thereafter, in the manner described in
General Partner Interest and Incentive
Distribution Rights below.
|
The preceding discussion is based on the assumptions that our
general partner maintains its 0.1% general partner interest and
that we do not issue additional classes of equity securities.
Distributions
of Available Cash from Operating Surplus After the Subordination
Period
Our partnership agreement requires that we make distributions of
available cash from operating surplus for any quarter after the
subordination period in the following manner:
|
|
|
|
|
first, 99.9% to all unitholders, pro rata, and 0.1% to
our general partner, until we distribute for each outstanding
unit an amount equal to the minimum quarterly distribution for
that quarter; and
|
|
|
|
thereafter, in the manner described in
General Partner Interest and Incentive
Distribution Rights below.
|
The preceding discussion is based on the assumptions that our
general partner maintains its 0.1% general partner interest and
that we do not issue additional classes of equity securities.
General
Partner Interest and Incentive Distribution Rights
Our partnership agreement provides that our general partner
initially will be entitled to 0.1% of all distributions that we
make prior to our liquidation. Our general partner has the
right, but not the obligation, to contribute a proportionate
amount of capital to us to maintain its 0.1% general partner
interest if we issue additional units. Our general
partners 0.1% interest, and the percentage of our cash
distributions to which it is entitled, will be proportionately
reduced if we issue additional units in the future and our
general partner does not contribute a proportionate amount of
capital to us to maintain its 0.1% general partner interest. Our
general partner will be entitled to make a capital contribution
in order to maintain its 0.1% general partner interest in the
form of the contribution to us of common units based on the
current market value of the contributed common units.
Incentive distribution rights represent the right to receive an
increasing percentage (14.9% and 24.9%) of quarterly
distributions of available cash from operating surplus after the
minimum quarterly distribution and the target distribution
levels have been achieved. Our general partner currently holds
the incentive distribution rights, but may transfer these rights
separately from its general partner interest, subject to
restrictions in the partnership agreement. The Funds
collectively own, through non-voting membership interests in our
general partner, 50.0% of the economic interest in our incentive
distribution rights and of any common units issued to our
general partner in connection with a reset of the incentive
distribution rights.
91
The following discussion assumes that our general partner
maintains its 0.1% general partner interest, that there are no
arrearages on common units and that our general partner
continues to own the incentive distribution rights.
If for any quarter:
|
|
|
|
|
we have distributed available cash from operating surplus to the
common and subordinated unitholders in an amount equal to the
minimum quarterly distribution; and
|
|
|
|
we have distributed available cash from operating surplus on
outstanding common units in an amount necessary to eliminate any
cumulative arrearages in payment of the minimum quarterly
distribution;
|
then, our partnership agreement requires that we distribute any
additional available cash from operating surplus for that
quarter among the unitholders and the general partner in the
following manner:
|
|
|
|
|
first, 99.9% to all unitholders, pro rata, and 0.1% to
our general partner, until each unitholder receives a total of
$ per unit for that quarter (the
first target distribution);
|
|
|
|
second, 85.0% to all unitholders, pro rata, and 15.0% to
our general partner, until each unitholder receives a total of
$ per unit for that quarter (the
second target distribution); and
|
|
|
|
thereafter, 75.0% to all unitholders, pro rata, and 25.0%
to our general partner.
|
Percentage
Allocations of Available Cash from Operating Surplus
The following table illustrates the percentage allocations of
available cash from operating surplus between the unitholders
and our general partner based on the specified target
distribution levels. The amounts set forth under Marginal
Percentage Interest in Distributions are the percentage
interests of our general partner and the unitholders in any
available cash from operating surplus we distribute up to and
including the corresponding amount in the column Total
Quarterly Distribution per Unit. The percentage interests
shown for our unitholders and our general partner for the
minimum quarterly distribution are also applicable to quarterly
distribution amounts that are less than the minimum quarterly
distribution. The percentage interests set forth below for our
general partner include its 0.1% general partner interest and
assume there are no arrearages on common units and our general
partner has contributed any additional capital to maintain its
0.1% general partner interest and our general partner has not
transferred its incentive distribution rights.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Quarterly
|
|
Marginal Percentage Interest in Distributions
|
|
|
Distribution per Unit
|
|
Unitholders
|
|
General Partner
|
|
Minimum Quarterly Distribution
|
|
$
|
|
|
|
|
99.9
|
%
|
|
|
0.1
|
%
|
First Target Distribution
|
|
above $
|
up to $
|
|
|
|
99.9
|
%
|
|
|
0.1
|
%
|
Second Target Distribution
|
|
above $
|
up to $
|
|
|
|
85.0
|
%
|
|
|
15.0
|
%
|
Thereafter
|
|
above $
|
|
|
|
|
75.0
|
%
|
|
|
25.0
|
%
|
General
Partners Right to Reset Incentive Distribution
Levels
Our general partner, as the holder of our incentive distribution
rights, has the right under our partnership agreement to elect
to relinquish the right to receive incentive distribution
payments based on the initial cash target distribution levels
and to reset, at higher levels, the minimum quarterly
distribution amount and cash target distribution levels upon
which the incentive distribution payments to our general partner
would be set. Our general partners right to reset the
minimum quarterly distribution amount and the target
distribution levels upon which the incentive distributions
payable to our general partner are based may be exercised,
without approval of our unitholders or the special committee of
our general partner, at any time when there are no subordinated
units outstanding and we have made cash distributions to the
holders of the incentive distribution rights at the highest
level of incentive distribution for each of the prior four
consecutive fiscal quarters. The reset minimum quarterly
distribution amount and target distribution levels will be
higher than the minimum quarterly distribution amount and the
target distribution levels prior to the reset such that our
general partner will not receive any incentive distributions
under the reset target distribution levels until cash
92
distributions per unit following this event increase as
described below. We anticipate that our general partner would
exercise this reset right (if at all) to facilitate acquisitions
or internal growth projects that would otherwise not be
sufficiently accretive to cash distributions per common unit,
taking into account the existing levels of incentive
distribution payments being made to our general partner.
In connection with the resetting of the minimum quarterly
distribution amount and the target distribution levels and the
corresponding relinquishment by our general partner of incentive
distribution payments based on the target cash distributions
prior to the reset, our general partner will be entitled to
receive a number of newly issued common units and general
partner units based on a predetermined formula described below
that takes into account the cash parity value of the
average cash distributions related to the incentive distribution
rights received by our general partner for the two quarters
prior to the reset event as compared to the average cash
distributions per common unit during this period. Our general
partner will be issued the number of general partner units
necessary to maintain our general partners interest in us
immediately prior to the reset election.
The number of common units that our general partner would be
entitled to receive from us in connection with a resetting of
the minimum quarterly distribution amount and the target
distribution levels then in effect would be equal to the
quotient determined by dividing (x) the average amount of
cash distributions received by our general partner in respect of
its incentive distribution rights during the two consecutive
fiscal quarters ended immediately prior to the date of such
reset election by (y) the average of the amount of cash
distributed per common unit during each of these two quarters.
Following any reset election by our general partner, the minimum
quarterly distribution amount will be reset to an amount equal
to the average cash distribution amount per unit for the two
fiscal quarters immediately preceding the reset election (which
amount we refer to as the reset minimum quarterly
distribution) and the target distribution levels will be
reset to be correspondingly higher such that we would distribute
all of our available cash from operating surplus for each
quarter thereafter as follows:
|
|
|
|
|
first, 99.9% to all unitholders, pro rata, and 0.1% to
our general partner, until each unitholder receives an amount
equal to 115% of the reset minimum quarterly distribution for
that quarter;
|
|
|
|
second, 85.0% to all unitholders, pro rata, and 15.0% to
our general partner, until each unitholder receives an amount
per unit equal to 125% of the reset minimum quarterly
distribution for the quarter; and
|
|
|
|
thereafter, 75.0% to all unitholders, pro rata, and 25.0%
to our general partner.
|
The following table illustrates the percentage allocation of
available cash from operating surplus between the unitholders
and our general partner at various cash distribution levels
(i) pursuant to the cash distribution provisions of our
partnership agreement in effect at the closing of this offering,
as well as (ii) following a hypothetical reset of the
minimum quarterly distribution and target distribution levels
based on the assumption that the average quarterly cash
distribution amount per common unit during the two fiscal
quarters immediately preceding the reset election was
$ .
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly
|
|
Marginal Percentage Interest in
|
|
Quarterly Distribution per
|
|
|
Distribution per Unit
|
|
Distributions
|
|
Unit Following Hypothetical
|
|
|
Prior to Reset
|
|
Unitholders
|
|
General Partner
|
|
Reset
|
|
Minimum quarterly distribution
|
|
|
$
|
|
|
|
99.9
|
%
|
|
|
0.1
|
%
|
|
$
|
First target distribution
|
|
|
up to $
|
|
|
|
99.9
|
%
|
|
|
0.1
|
%
|
|
up
to $ (1)
|
Second target distribution
|
|
|
above $ up to $
|
|
|
|
85.0
|
%
|
|
|
15.0
|
%
|
|
above $ (1) up to $ (2)
|
Thereafter
|
|
|
above $
|
|
|
|
75.0
|
%
|
|
|
25.0
|
%
|
|
above
$ (2)
|
|
|
|
(1) |
|
This amount is 115.0% of the hypothetical reset minimum
quarterly distribution. |
|
(2) |
|
This amount is 125.0% of the hypothetical reset minimum
quarterly distribution. |
93
The following table illustrates the total amount of available
cash from operating surplus that would be distributed to the
unitholders and our general partner, including in respect of
incentive distribution rights based on an average of the amounts
distributed for a quarter for the two quarters immediately prior
to the reset. The table assumes that immediately prior to the
reset there would be common units
outstanding, our general partner has maintained its 0.1% general
partner interest, and the average distribution to each common
unit would be $ for the two
quarters prior to the reset.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly
|
|
|
Distributions to
|
|
|
Cash Distributions to General Partner Prior to Reset
|
|
|
|
|
|
|
Distribution per
|
|
|
Common
|
|
|
|
|
|
|
|
|
Incentive
|
|
|
|
|
|
|
|
|
|
Unit Prior to
|
|
|
Unitholders
|
|
|
Common
|
|
|
0.1% General
|
|
|
Distribution
|
|
|
|
|
|
Total
|
|
|
|
Reset
|
|
|
Prior to Reset
|
|
|
Units
|
|
|
Partner Interest
|
|
|
Rights
|
|
|
Total
|
|
|
Distributions
|
|
|
Minimum quarterly distribution
|
|
|
$
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
First target distribution
|
|
|
up to $
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second target distribution
|
|
|
above $ up to $
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thereafter
|
|
|
above $
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table illustrates the total amount of available
cash from operating surplus that would be distributed to the
unitholders and our general partner, including in respect of
incentive distribution rights, with respect to the quarter in
which the reset occurs. The table reflects that as a result of
the reset there would be common
units outstanding, our general partners 0.1% interest has
been maintained, and the average distribution to each common
unit would be $ . The number of
common units to be issued to our general partner upon the reset
was calculated by dividing (i) the average of the amounts
received by our general partner in respect of its incentive
distribution rights for the two quarters prior to the reset as
shown in the table above, or $ , by (ii) the average
available cash distributed on each common unit for the two
quarters prior to the reset as shown in the table above, or
$ .
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarterly
|
|
|
Distributions to
|
|
|
Cash Distributions to General Partner After Reset
|
|
|
|
|
|
|
Distribution per
|
|
|
Common
|
|
|
|
|
|
|
|
|
Incentive
|
|
|
|
|
|
|
|
|
|
Unit Prior to
|
|
|
Unitholders
|
|
|
Common
|
|
|
0.1% General
|
|
|
Distribution
|
|
|
|
|
|
Total
|
|
|
|
Reset
|
|
|
Prior to Reset
|
|
|
Units
|
|
|
Partner Interest
|
|
|
Rights
|
|
|
Total
|
|
|
Distributions
|
|
|
Minimum quarterly distribution
|
|
|
$
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
First target distribution
|
|
|
up to $
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second target distribution
|
|
|
above $ up to $
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thereafter
|
|
|
above $
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our general partner will be entitled to cause the minimum
quarterly distribution amount and the target distribution levels
to be reset on more than one occasion, provided that it may not
make a reset election except at a time when it has received
incentive distributions for the prior four consecutive fiscal
quarters based on the highest level of incentive distributions
that it is entitled to receive under our partnership agreement.
Distributions
from Capital Surplus
How
Distributions from Capital Surplus Will Be Made
We will make distributions of available cash from capital
surplus, if any, in the following manner:
|
|
|
|
|
First, 99.9% to all unitholders, pro rata, and 0.1% to
our general partner, until the minimum quarterly distribution is
reduced to zero, as described below;
|
94
|
|
|
|
|
Second, 99.9% to the common unitholders, pro rata, and
0.1% to our general partner, until we distribute for each common
unit, an amount of available cash from capital surplus equal to
any unpaid arrearages in payment of the minimum quarterly
distribution on the common units; and
|
|
|
|
Thereafter, we will make all distributions of available
cash from capital surplus as if they were from operating surplus.
|
The preceding discussion is based on the assumption that our
general partner maintains its 0.1% general partner interest and
that we do not issue additional classes of equity securities.
Effect
of a Distribution from Capital Surplus
Our partnership agreement treats a distribution of capital
surplus as the repayment of the initial unit price from this
initial public offering, which is a return of capital. The
initial public offering price less any distributions of capital
surplus per unit is referred to as the unrecovered initial
unit price. Each time a distribution of capital surplus is
made, the minimum quarterly distribution and the target
distribution levels will be reduced in the same proportion as
the corresponding reduction in the unrecovered initial unit
price. Because distributions of capital surplus will reduce the
minimum quarterly distribution after any of these distributions
are made, it may be easier for our general partner to receive
incentive distributions and for the subordinated units to
convert into common units. However, any distribution of capital
surplus before the unrecovered initial unit price is reduced to
zero cannot be applied to the payment of the minimum quarterly
distribution or any arrearages.
Once we distribute capital surplus on a unit issued in this
offering in an amount equal to the initial unit price, our
partnership agreement specifies that the minimum quarterly
distribution and the target distribution levels will be reduced
to zero. Our partnership agreement specifies that we then make
all future distributions as distributions from operating
surplus, with 75.0% being paid to the holders of units and 25.0%
to our general partner. The percentage interests shown for our
general partner include its 0.1% general partner interest and
assume our general partner has not transferred the incentive
distribution rights.
Adjustment
to the Minimum Quarterly Distribution and Target Distribution
Levels
In addition to adjusting the minimum quarterly distribution and
target distribution levels to reflect a distribution of capital
surplus, if we combine our units into fewer units or subdivide
our units into a greater number of units, our partnership
agreement specifies that the following items will be
proportionately adjusted:
|
|
|
|
|
the minimum quarterly distribution;
|
|
|
|
target distribution levels;
|
|
|
|
the unrecovered initial unit price; and
|
|
|
|
the number of common units into which a subordinated unit is
convertible.
|
For example, if a
two-for-one
split of the common units should occur, the minimum quarterly
distribution, the target distribution levels and the unrecovered
initial unit price would each be reduced to 50% of its initial
level, and each subordinated unit would be convertible into two
common units. Our partnership agreement provides that we do not
make any adjustment by reason of the issuance of additional
units for cash or property.
In addition, if legislation is enacted or if existing law is
modified or interpreted by a governmental taxing authority, so
that we become taxable as a corporation or otherwise subject to
taxation as an entity for federal, state or local income tax
purposes, our partnership agreement specifies that the minimum
quarterly distribution and the target distribution levels may be
reduced by multiplying each distribution level by a fraction,
the numerator of which is available cash for that quarter and
the denominator of which is the sum of available cash for that
quarter plus our general partners estimate of our
aggregate liability for the quarter for such income taxes
payable by reason of such legislation or interpretation. To the
extent that the actual tax liability differs from the estimated
tax liability for any quarter, the difference will be accounted
for in subsequent
95
quarters. In addition, as a result of a change in law or
interpretation thereof, we or any of our subsidiaries is treated
as an association taxable as a corporation or is otherwise
subject to additional taxation as an entity for
U.S. federal, state, local or
non-U.S. income
or withholding tax purposes, our general partner may, in its
sole discretion, reduce the minimum quarterly distribution and
the target distribution levels by multiplying each by a
fraction, the numerator of which is available cash for that
quarter (after deducting our general partners estimate of
our aggregate liability for the quarter for such income and
withholding taxes payable by reason of such change in laws or
interpretation) and the denominator of which is the sum of
available cash for that quarter plus our general partners
estimate of our aggregate liability for the quarter for such
income and withholding taxes payable by reason of such change in
laws or interpretation. To the extent that the actual tax
liability differs from the estimated tax liability for any
quarter, the difference will be accounted for in subsequent
quarters.
Distributions
of Cash Upon Liquidation
General
If we dissolve in accordance with the partnership agreement, we
will sell or otherwise dispose of our assets in a process called
liquidation. We will first apply the proceeds of liquidation to
the payment of our creditors. We will distribute any remaining
proceeds to the unitholders and the general partner, in
accordance with their capital account balances, as adjusted to
reflect any gain or loss upon the sale or other disposition of
our assets in liquidation.
The allocations of gain and loss upon liquidation are intended,
to the extent possible, to entitle the holders of outstanding
common units to a preference over the holders of outstanding
subordinated units upon our liquidation, to the extent required
to permit common unitholders to receive their unrecovered
initial unit price plus the minimum quarterly distribution for
the quarter during which liquidation occurs plus any unpaid
arrearages in payment of the minimum quarterly distribution on
the common units. However, there may not be sufficient gain upon
our liquidation to enable the holders of common units to fully
recover all of these amounts, even though there may be cash
available for distribution to the holders of subordinated units.
Any further net gain recognized upon liquidation will be
allocated in a manner that takes into account the incentive
distribution rights of our general partner.
Manner
of Adjustments for Gain
The manner of the adjustment for gain is set forth in the
partnership agreement. If our liquidation occurs before the end
of the subordination period, we will allocate any gain to the
partners in the following manner:
|
|
|
|
|
first, to our general partner and the holders of units
who have negative balances in their capital accounts to the
extent of and in proportion to those negative balances;
|
|
|
|
second, 99.9% to the common unitholders, pro rata, and
0.1% to our general partner, until the capital account for each
common unit is equal to the sum of: (1) the unrecovered
initial unit price; (2) the amount of the minimum quarterly
distribution for the quarter during which our liquidation
occurs; and (3) any unpaid arrearages in payment of the
minimum quarterly distribution;
|
|
|
|
third, 99.9% to the subordinated unitholders, pro rata,
and 0.1% to our general partner, until the capital account for
each subordinated unit is equal to the sum of: (1) the
unrecovered initial unit price; and (2) the amount of the
minimum quarterly distribution for the quarter during which our
liquidation occurs;
|
|
|
|
fourth, 99.9% to all unitholders, pro rata, and 0.1% to
our general partner, until we allocate under this paragraph an
amount per unit equal to: (1) the sum of the excess of the
first target distribution per unit over the minimum quarterly
distribution per unit for each quarter of our existence; less
(2) the cumulative amount per unit of any distributions of
available cash from operating surplus in excess of the minimum
quarterly distribution per unit that we distributed 99.9% to the
unitholders, pro rata, and 0.1% to our general partner, for each
quarter of our existence;
|
96
|
|
|
|
|
fifth, 85.0% to all unitholders, pro rata, and 15.0% to
our general partner, until we allocate under this paragraph an
amount per unit equal to: (1) the sum of the excess of the
second target distribution per unit over the first target
distribution per unit for each quarter of our existence; less
(2) the cumulative amount per unit of any distributions of
available cash from operating surplus in excess of the first
target distribution per unit that we distributed 85.0% to the
unitholders, pro rata, and 15.0% to our general partner for each
quarter of our existence; and
|
|
|
|
thereafter, 75.0% to all unitholders, pro rata, and 25.0%
to our general partner.
|
The percentage interests set forth above for our general partner
include its 0.1% general partner interest and assume our general
partner has not transferred the incentive distribution rights.
If the liquidation occurs after the end of the subordination
period, the distinction between common and subordinated units
will disappear, so that clause (3) of the second bullet
point above and all of the third bullet point above will no
longer be applicable.
Manner
of Adjustments for Losses
If our liquidation occurs before the end of the subordination
period, we will generally allocate any loss to our general
partner and the unitholders in the following manner:
|
|
|
|
|
first, 99.9% to holders of subordinated units in
proportion to the positive balances in their capital accounts
and 0.1% to our general partner, until the capital accounts of
the subordinated unitholders have been reduced to zero;
|
|
|
|
second, 99.9% to the holders of common units in
proportion to the positive balances in their capital accounts
and 0.1% to our general partner, until the capital accounts of
the common unitholders have been reduced to zero; and
|
|
|
|
thereafter, 100.0% to our general partner.
|
If the liquidation occurs after the end of the subordination
period, the distinction between common and subordinated units
will disappear, so that all of the first bullet point above will
no longer be applicable.
Adjustments
to Capital Accounts
Our partnership agreement requires that we make adjustments to
capital accounts upon the issuance of additional units. In this
regard, our partnership agreement specifies that we allocate any
unrealized and, for tax purposes, unrecognized gain or loss
resulting from the adjustments to the unitholders and the
general partner in the same manner as we allocate gain or loss
upon liquidation. In the event that we make positive adjustments
to the capital accounts upon the issuance of additional units,
our partnership agreement requires that we allocate any later
negative adjustments to the capital accounts resulting from the
issuance of additional units or upon our liquidation in a manner
which results, to the extent possible, in the general
partners capital account balances equaling the amount
which they would have been if no earlier positive adjustments to
the capital accounts had been made.
97
SELECTED
HISTORICAL AND PRO FORMA FINANCIAL DATA
We were formed in April 2011 and do not have historical
financial operating results. Therefore, in this prospectus, we
present the historical financial statements of our predecessor.
The following table shows selected historical financial data of
our predecessor and unaudited pro forma financial information of
Memorial Production Partners LP. Due to the factors described in
Managements Discussion and Analysis of Financial
Condition and Results of Operations Overview,
our future results of operations will not be comparable to the
historical results of our predecessor. The selected historical
financial data as of December 31, 2009 and 2010 and for the
years ended December 31, 2008, 2009 and 2010 are derived
from the audited historical combined financial statements of our
predecessor included elsewhere in this prospectus. The selected
historical financial data as of December 31, 2006, 2007 and
2008 and for the years ended December 31, 2006 and 2007 are
derived from our predecessors unaudited financial records.
The selected historical financial data presented as of
March 31, 2011 and for the three months ended
March 31, 2010 and 2011 are derived from the unaudited
historical combined financial statements of our predecessor
included elsewhere in this prospectus.
The selected pro forma financial data as of March 31, 2011
and for the three months ended March 31, 2011 and for the
year ended December 31, 2010 are derived from the unaudited
pro forma combined financial statements of Memorial Production
Partners LP included elsewhere in this prospectus. The pro forma
adjustments have been prepared as if certain transactions, which
have been completed or which will be effected prior to or in
connection with the closing of this offering, had taken place on
March 31, 2011, in the case of the unaudited pro forma
combined balance sheet, or as of January 1, 2010, in the
case of the unaudited pro forma combined statements of
operations. These transactions include:
|
|
|
|
|
adjustments to reflect the acquisitions of oil and natural gas
properties consummated in June 2010, April 2011, and May 2011 by
our predecessor;
|
|
|
|
the contribution by Memorial Resource and certain of its
subsidiaries, including our predecessor, to us of the
Partnership Properties in exchange
for
common
units, subordinated
units and $ million in cash
and the issuance to our general partner
of
general partner units, representing a 0.1% general partner
interest in us, and all of our incentive distribution rights;
|
|
|
|
the issuance and sale by us to the public
of
common units in this offering and the application of the net
proceeds as described in Use of Proceeds; and
|
|
|
|
our borrowing of approximately $130.0 million under our new
$ million revolving credit
facility and the application of the net proceeds as described in
Use of Proceeds. If the net proceeds from this
offering increase or decrease, then our borrowing under the new
revolving credit facility would correspondingly decrease or
increase, respectively.
|
You should read the following table in conjunction with
Summary Our Partnership Structure and
Formation Transactions, Use of Proceeds,
Managements Discussion and Analysis of Financial
Condition and Results of Operations, the historical
combined financial statements of our predecessor and the
unaudited pro forma combined financial statements of Memorial
Production Partners LP included elsewhere in this
98
prospectus. Among other things, those historical and unaudited
pro forma financial statements include more detailed information
regarding the basis of presentation for the following
information.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Memorial Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners LP
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
|
|
|
|
Our Predecessor
|
|
|
Year
|
|
|
Months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
Year Ended December 31,
|
|
|
March 31,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
$
|
112
|
|
|
$
|
11,949
|
|
|
$
|
49,313
|
|
|
$
|
24,541
|
|
|
$
|
37,308
|
|
|
$
|
7,879
|
|
|
$
|
11,641
|
|
|
$
|
87,762
|
|
|
$
|
20,648
|
|
Other income
|
|
|
21
|
|
|
|
153
|
|
|
|
622
|
|
|
|
319
|
|
|
|
1,433
|
|
|
|
67
|
|
|
|
103
|
|
|
|
1,404
|
|
|
|
99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
133
|
|
|
|
12,102
|
|
|
|
49,935
|
|
|
|
24,860
|
|
|
|
38,741
|
|
|
|
7,946
|
|
|
|
11,744
|
|
|
|
89,166
|
|
|
|
20,747
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
156
|
|
|
|
2,873
|
|
|
|
8,843
|
|
|
|
11,207
|
|
|
|
13,974
|
|
|
|
2,220
|
|
|
|
5,170
|
|
|
|
23,052
|
|
|
|
6,685
|
|
Exploration
|
|
|
|
|
|
|
|
|
|
|
374
|
|
|
|
2,690
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
Production and ad valorem taxes
|
|
|
7
|
|
|
|
1,113
|
|
|
|
3,127
|
|
|
|
1,464
|
|
|
|
2,112
|
|
|
|
509
|
|
|
|
693
|
|
|
|
7,387
|
|
|
|
1,703
|
|
Depreciation, depletion and amortization
|
|
|
233
|
|
|
|
18,144
|
|
|
|
12,353
|
|
|
|
15,226
|
|
|
|
20,066
|
|
|
|
4,352
|
|
|
|
4,450
|
|
|
|
34,772
|
|
|
|
7,026
|
|
Impairment of proved oil and natural gas properties
|
|
|
1,430
|
|
|
|
|
|
|
|
14,166
|
|
|
|
3,480
|
|
|
|
11,800
|
|
|
|
1,691
|
|
|
|
|
|
|
|
9,509
|
|
|
|
|
|
General and administrative
|
|
|
1,390
|
|
|
|
2,937
|
|
|
|
3,835
|
|
|
|
4,811
|
|
|
|
6,116
|
|
|
|
1,108
|
|
|
|
1,474
|
|
|
|
5,819
|
|
|
|
1,399
|
|
Accretion
|
|
|
1
|
|
|
|
319
|
|
|
|
224
|
|
|
|
320
|
|
|
|
663
|
|
|
|
64
|
|
|
|
210
|
|
|
|
1,072
|
|
|
|
276
|
|
(Gain) loss on derivative instruments
|
|
|
|
|
|
|
734
|
|
|
|
(9,815
|
)
|
|
|
(10,834
|
)
|
|
|
(10,264
|
)
|
|
|
(6,636
|
)
|
|
|
703
|
|
|
|
(10,264
|
)
|
|
|
703
|
|
Gain on sale of properties
|
|
|
|
|
|
|
|
|
|
|
(7,395
|
)
|
|
|
(7,851
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
(508
|
)
|
|
|
744
|
|
|
|
|
|
|
|
304
|
|
|
|
890
|
|
|
|
|
|
|
|
|
|
|
|
890
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
2,709
|
|
|
|
26,864
|
|
|
|
25,712
|
|
|
|
20,817
|
|
|
|
45,395
|
|
|
|
3,308
|
|
|
|
12,692
|
|
|
|
72,273
|
|
|
|
17,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
(2,576
|
)
|
|
|
(14,762
|
)
|
|
|
24,223
|
|
|
|
4,043
|
|
|
|
(6,654
|
)
|
|
|
4,638
|
|
|
|
(948
|
)
|
|
|
16,893
|
|
|
|
2,955
|
|
Interest expense
|
|
|
(7
|
)
|
|
|
(1,135
|
)
|
|
|
(3,138
|
)
|
|
|
(2,937
|
)
|
|
|
(4,438
|
)
|
|
|
(606
|
)
|
|
|
(1,035
|
)
|
|
|
(4,365
|
)
|
|
|
(1,092
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(2,583
|
)
|
|
|
(15,897
|
)
|
|
|
21,085
|
|
|
|
1,106
|
|
|
|
(11,092
|
)
|
|
|
4,032
|
|
|
|
(1,983
|
)
|
|
|
12,528
|
|
|
|
1,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(225
|
)
|
|
|
|
|
|
|
|
|
|
|
(225
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(2,583
|
)
|
|
$
|
(15,897
|
)
|
|
$
|
21,085
|
|
|
$
|
1,106
|
|
|
$
|
(11,317
|
)
|
|
$
|
4,032
|
|
|
$
|
(1,983
|
)
|
|
$
|
12,303
|
|
|
$
|
1,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
(1,282
|
)
|
|
$
|
6,742
|
|
|
$
|
32,838
|
|
|
$
|
12,672
|
|
|
$
|
20,288
|
|
|
$
|
3,935
|
|
|
$
|
2,999
|
|
|
|
|
|
|
|
|
|
Net cash (used in) investing activities
|
|
|
(6,538
|
)
|
|
|
(97,416
|
)
|
|
|
(45,547
|
)
|
|
|
(24,947
|
)
|
|
|
(116,687
|
)
|
|
|
(10,601
|
)
|
|
|
(7,898
|
)
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
8,500
|
|
|
|
93,196
|
|
|
|
11,619
|
|
|
|
15,989
|
|
|
|
96,756
|
|
|
|
9,434
|
|
|
|
1,375
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
|
|
|
|
|
|
|
|
$
|
33,971
|
|
|
$
|
24,340
|
|
|
$
|
23,239
|
|
|
$
|
5,042
|
|
|
$
|
5,602
|
|
|
$
|
59,608
|
|
|
$
|
12,155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Memorial
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners LP
|
|
|
|
Our Predecessor
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
Year Ended December 31,
|
|
|
March 31,
|
|
|
March 31,
|
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2011
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital (deficit)
|
|
$
|
1,107
|
|
|
$
|
(1,684
|
)
|
|
$
|
(966
|
)
|
|
$
|
9,494
|
|
|
$
|
4,116
|
|
|
$
|
2,490
|
|
|
$
|
1,318
|
|
Total assets
|
|
|
6,565
|
|
|
|
99,021
|
|
|
|
145,529
|
|
|
|
146,153
|
|
|
|
248,540
|
|
|
|
245,042
|
|
|
|
435,107
|
|
Total debt
|
|
|
3,500
|
|
|
|
46,726
|
|
|
|
62,536
|
|
|
|
61,784
|
|
|
|
115,428
|
|
|
|
112,584
|
|
|
|
130,000
|
|
Partners capital
|
|
|
2,416
|
|
|
|
36,488
|
|
|
|
54,576
|
|
|
|
72,988
|
|
|
|
105,801
|
|
|
|
108,039
|
|
|
|
278,543
|
|
99
MANAGEMENTS
DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This Managements Discussion and Analysis of Financial
Condition and Results of Operations contains the following
information:
|
|
|
|
|
a discussion of our business on a pro forma basis,
including:
|
|
|
|
|
|
a general overview of our properties;
|
|
|
|
our results of operations;
|
|
|
|
our liquidity and capital resources; and
|
|
|
|
our quantitative and qualitative disclosures about market
risk; and
|
|
|
|
|
|
a discussion of our predecessors business on a
historical basis, including:
|
|
|
|
|
|
our predecessors results of operations;
|
|
|
|
our predecessors liquidity and capital resources;
and
|
|
|
|
our predecessors quantitative and qualitative
disclosures about market risk.
|
The following Managements Discussion and Analysis of
Financial Condition and Results of Operations should be read in
conjunction with the Selected Historical and Pro Forma
Financial Data and the accompanying financial statements
and related notes included elsewhere in this prospectus. Unless
otherwise indicated, all references to financial or operating
data on a pro forma basis give effect to the transactions
described under Summary Our Partnership
Structure and Formation Transactions and in the unaudited
pro forma combined financial statements included elsewhere in
this prospectus. The following discussion contains
forward-looking statements that reflect our future plans,
estimates, beliefs and expected performance. The forward-looking
statements are dependent upon events, risks and uncertainties
that may be outside our control. Our actual results could differ
materially from those discussed in these forward-looking
statements. Factors that could cause or contribute to such
differences include, but are not limited to, market prices for
oil and natural gas, production volumes, estimates of proved
reserves, capital expenditures, economic and competitive
conditions, regulatory changes and other uncertainties, as well
as those factors discussed below and elsewhere in this
prospectus, particularly in Risk Factors and
Forward-Looking Statements, all of which are
difficult to predict. In light of these risks, uncertainties and
assumptions, the forward-looking events discussed may not
occur.
Overview
We are a Delaware limited partnership formed in April 2011 by
Memorial Resource to own and acquire oil and natural gas
properties in North America. At the closing of this offering,
Memorial Resource and certain of its subsidiaries, including our
predecessor, will contribute to us (1) specified oil and
natural gas properties, which we refer to collectively as the
Partnership Properties, and (2) commodity
derivative contracts for the six months ending December 31,
2011 and the years ending December 31, 2012, 2013, 2014,
and 2015 covering approximately 76%, 75%, 69%, 14% and 8%,
respectively, of our estimated production from our total proved
developed producing reserves existing as of December 31,
2010, based on our reserve reports.
Our
Properties
Following the contribution of the Partnership Properties to us,
we will own oil and natural gas properties located in South and
East Texas. Based on proved reserves volumes at
December 31, 2010, we or Memorial Resource will operate 94%
of the properties in which we have interests, and we will own an
average working interest of 41% across our oil and natural gas
properties. As of December 31, 2010, we had interests in
1,290 gross (609 net) producing wells across our
properties, with an average working interest of 47%. As of
December 31, 2010, our total estimated proved reserves were
approximately 325 Bcfe, of which approximately
100
81% were classified as proved developed reserves. As of
December 31, 2010, our estimated proved reserves had a
standardized measure of $359.2 million. Based on our pro
forma average net production for the year ended
December 31, 2010 of 52 MMcfe/d, our total estimated
proved reserves had a
reserve-to-production
ratio of 17 years.
Memorial
Resources Retained Properties
After giving effect to the formation transactions, Memorial
Resource had (i) total estimated proved reserves of
1,036 Bcfe at December 31, 2010, primarily located in
East Texas, North Louisiana and the Rockies, of which
approximately 81% were natural gas, and approximately 34% were
classified as proved developed reserves, and (ii) interests
in over 398,000 gross (173,000 net) acres of undeveloped
properties.
How We
Conduct Our Business and Evaluate Our Operations
We use a variety of financial and operational metrics to assess
the performance of our oil and natural gas operations, including:
|
|
|
|
|
production volumes;
|
|
|
|
realized prices on the sale of oil and natural gas, including
the effect of our derivative contracts;
|
|
|
|
lease operating expenses;
|
|
|
|
general and administrative expenses; and
|
|
|
|
Adjusted EBITDA.
|
Production
Volumes
Production volumes directly impact our results of operations.
For more information about our predecessors and our pro
forma production volumes, please read
Historical Pro Forma Financial and Operating
Data.
Realized
Prices on the Sale of Oil and Natural Gas
Factors Affecting the Sales Price of Oil and Natural
Gas. We will market our oil and natural gas
production to a variety of purchasers based on regional pricing.
The relative prices of oil and natural gas are determined by the
factors impacting global and regional supply and demand
dynamics, such as economic conditions, production levels,
weather cycles and other events. In addition, relative prices
are heavily influenced by product quality and location relative
to consuming and refining markets.
Natural Gas. The NYMEX-Henry Hub price of
natural gas is a widely used benchmark for the pricing of
natural gas in the United States. Similar to oil, the actual
prices realized from the sale of natural gas differ from the
quoted NYMEX-Henry Hub price as a result of quality and location
differentials. Quality differentials to NYMEX-Henry Hub prices
result from: (1) the Btu content of natural gas, which
measures its heating value, and (2) the percentage of
sulfur,
CO2
and other inert content by volume. Wet natural gas with a high
Btu content sells at a premium to low Btu content dry natural
gas because it yields a greater quantity of NGLs. Natural gas
with low sulfur and
CO2
content sells at a premium to natural gas with high sulfur and
CO2
content because of the added cost to separate the sulfur and
CO2
from the natural gas to render it marketable. The wet natural
gas is processed in third-party natural gas plants and residue
natural gas as well as NGLs are recovered and sold. Our wellhead
Btu has an average energy content greater than 1,000 Btu and
minimal sulfur and
CO2
content and generally receives a premium valuation. The dry
natural gas residue from the Partnership Properties is generally
sold based on index prices in the region from which it is
produced.
Location differentials to NYMEX-Henry Hub prices result from
variances in transportation costs based on the natural gas
proximity to the major consuming markets to which it is
ultimately delivered. Also affecting the differential is the
processing fee deduction retained by the natural gas processing
plant generally in the
101
form of percentage of proceeds. Generally, these index prices
have historically been at a discount to NYMEX-Henry Hub natural
gas prices.
Oil. The NYMEX-WTI futures price is a widely
used benchmark in the pricing of domestic and imported oil in
the United States. The actual prices realized from the sale of
oil differ from the quoted NYMEX-WTI price as a result of
quality and location differentials. Quality differentials to
NYMEX-WTI prices result from the fact that crude oils differ
from one another in their molecular makeup, which plays an
important part in their refining and subsequent sale as
petroleum products. Among other things, there are two
characteristics that commonly drive quality differentials:
(1) the oils American Petroleum Institute, or API,
gravity and (2) the oils percentage of sulfur content
by weight. In general, lighter oil (with higher API gravity)
produces a larger number of lighter products, such as gasoline,
which have higher resale value, and, therefore, normally sells
at a higher price than heavier oil. Oil with low sulfur content
(sweet oil) is less expensive to refine and, as a
result, normally sells at a higher price than high
sulfur-content oil (sour oil).
Location differentials to NYMEX-WTI prices result from variances
in transportation costs based on the produced oils
proximity to the major consuming and refining markets to which
it is ultimately delivered. Oil that is produced close to major
consuming and refining markets, such as near Cushing, Oklahoma,
is in higher demand as compared to oil that is produced farther
from such markets. Consequently, oil that is produced close to
major consuming and refining markets normally realizes a higher
price (i.e., a lower location differential to NYMEX-WTI).
The oil produced from our properties is a combination of sweet
and sour oil, varying by location. We sell our oil at the
NYMEX-WTI price, which is adjusted for quality and
transportation differential, depending primarily on location and
purchaser. The differential varies, but our oil normally sells
at a discount to the NYMEX-WTI price.
In the past, oil and natural gas prices have been extremely
volatile, and we expect this volatility to continue. For
example, during the year ended December 31, 2010, the
NYMEX-WTI oil price ranged from a high of $91.49 per Bbl to a
low of $65.96 per Bbl, while the NYMEX-Henry Hub natural gas
price ranged from a high of $7.50 per MMBtu to a low of $1.83
per MMBtu. For the five years ended December 31, 2010, the
NYMEX-WTI oil price ranged from a high of $145.29 per Bbl to a
low of $31.41 per Bbl, while the NYMEX-Henry Hub natural gas
price ranged from a high of $13.31 per MMBtu to a low of $1.83
per MMBtu.
Commodity Derivative Contracts. We expect to
adopt a hedging policy designed to reduce the impact to our cash
flows from commodity price volatility. Under this policy, we
intend to enter into commodity derivative contracts covering
approximately 65% to 85% of our estimated production from total
proved developed producing reserves over a
three-to-five
year period at any given point of time. We may, however, from
time to time hedge more or less than this approximate range.
Additionally, we intend to individually identify these
non-speculative hedges as designated hedges for U.S.
federal income tax purposes as we enter into them.
At the closing of this offering, Memorial Resource will
contribute to us, in conjunction with the Partnership
Properties, commodity derivative contracts for the six months
ending December 31, 2011 and the years ending
December 31, 2012, 2013, 2014, and 2015 covering
approximately 76%, 75%, 69%, 14% and 8%, respectively, of our
estimated production from our total proved developed producing
reserves existing as of December 31, 2010, based on our
reserve reports. Please read Pro Forma
Liquidity and Capital Resources Commodity Derivative
Contracts. The following table reflects, with respect to
these
102
derivative contracts to be provided to us, the volumes of our
production covered by derivative contracts and the average
prices at which the production will be hedged:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ending December 31,
|
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
Natural Gas Derivative Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu/d)
|
|
|
5,682
|
|
|
|
6,164
|
|
|
|
4,932
|
|
|
|
|
|
|
|
|
|
Weighted-average fixed price
|
|
$
|
5.37
|
|
|
$
|
5.32
|
|
|
$
|
5.24
|
|
|
$
|
|
|
|
$
|
|
|
Collar contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu/d)
|
|
|
12,225
|
|
|
|
20,311
|
|
|
|
19,463
|
|
|
|
3,945
|
|
|
|
2,630
|
|
Weighted-average ceiling price
|
|
$
|
6.27
|
|
|
$
|
5.91
|
|
|
$
|
5.83
|
|
|
$
|
6.31
|
|
|
$
|
6.75
|
|
Weighted-average floor price
|
|
$
|
5.02
|
|
|
$
|
4.79
|
|
|
$
|
4.75
|
|
|
$
|
5.08
|
|
|
$
|
5.25
|
|
Put options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu/d)
|
|
|
8,285
|
|
|
|
2,295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average floor price
|
|
$
|
4.30
|
|
|
$
|
4.80
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Total natural gas volumes hedged (MMBtu/d):
|
|
|
26,192
|
|
|
|
28,770
|
|
|
|
24,395
|
|
|
|
3,945
|
|
|
|
2,630
|
|
Oil Derivative Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl/d)
|
|
|
114
|
|
|
|
148
|
|
|
|
156
|
|
|
|
105
|
|
|
|
|
|
Weighted-average ceiling price
|
|
$
|
110.87
|
|
|
$
|
115.12
|
|
|
$
|
116.94
|
|
|
$
|
117.72
|
|
|
$
|
|
|
Weighted-average floor price
|
|
$
|
84.81
|
|
|
$
|
86.67
|
|
|
$
|
87.16
|
|
|
$
|
90.00
|
|
|
$
|
|
|
Put options:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl/d)
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average floor price
|
|
$
|
85.00
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Natural Gas Liquids Derivative Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (Bbl/d)
|
|
|
62
|
|
|
|
125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average ceiling price
|
|
$
|
93.57
|
|
|
$
|
93.57
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Weighted-average floor price
|
|
$
|
75.16
|
|
|
$
|
75.16
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Lease Operating Expenses. We strive to
increase our production levels to maximize our revenue and cash
available for distribution. Lease operating expenses are the
costs incurred in the operation of producing properties and
workover costs. Expenses for utilities, direct labor, water
injection and disposal, and materials and supplies comprise the
most significant portion of our lease operating expenses. Lease
operating expenses do not include general and administrative
expenses or production and other taxes. Certain items, such as
direct labor and materials and supplies, generally remain
relatively fixed across broad production volume ranges, but can
fluctuate depending on activities performed during a specific
period. For instance, repairs to our pumping equipment or
surface facilities result in increased lease operating expenses
in periods during which they are performed.
A majority of our operating cost components are variable and
increase or decrease as the level of produced hydrocarbons and
water increases or decreases. For example, we incur power costs
in connection with various production related activities such as
pumping to recover oil and natural gas and separation and
treatment of water produced in connection with our oil and
natural gas production. Over the life of natural gas fields, the
amount of water produced may increase for a given volume of
natural gas production, and, as pressure declines in natural gas
wells that also produce water, more power will be needed to
provide energy to artificial lift systems that help to remove
produced water from the wells. Thus, production of a given
volume of natural gas gets more expensive each year as the
cumulative natural gas produced from a field increases until, at
some point, additional production becomes uneconomic. We believe
that one of managements areas
103
of core expertise lies in reducing these expenses, thus
extending the economic life of the field and improving the cash
margin of producing natural gas.
We monitor our operations to ensure that we are incurring
operating costs at the optimal level. Accordingly, we monitor
our production expenses and operating costs per well to
determine if any wells or properties should be shut in,
recompleted or sold. We typically evaluate our oil and natural
gas operating costs on a per Mcfe basis. This unit rate allows
us to monitor these costs in certain fields and geographic areas
to identify trends and to benchmark against other producers.
Production and Ad Valorem Taxes. Texas
regulates the development, production, gathering and sale of oil
and natural gas, including imposing production taxes and
requirements for obtaining drilling permits. For oil, Texas
currently imposes a production tax at 4.6% of the market value
of the oil produced and 3/16 of one cent per Bbl produced, and
for natural gas, Texas currently imposes a production tax of
7.5% of the market value of the natural gas. However, a
significant portion of the wells in Texas are either currently
exempt from production tax due to high cost natural gas
abatement or reduced rate for post production cost recoupment.
Ad valorem taxes are generally tied to the valuation of the oil
and natural gas properties; however, these valuations are
reasonably correlated to revenues, excluding the effects of any
commodity derivative contracts.
General and Administrative Expenses. At
the closing of this offering, we and our general partner will
enter into an omnibus agreement with Memorial Resource pursuant
to which, among other things, it will perform all operational,
management and administrative services on our general
partners and our behalf. Our partnership agreement
provides that our general partner will determine in good faith
the expenses that are allocated to us, including expenses
incurred by our general partner and its affiliates on our
behalf. For a detailed description of the omnibus agreement,
please read Certain Relationships and Related Party
Transactions Agreements Governing the
Transactions Omnibus Agreement. Under our
partnership agreement and the omnibus agreement, we will
reimburse Memorial Resource for all direct and indirect costs
incurred on our behalf, including the $2.5 million of
incremental annual expenses we expect to incur as a result of
becoming a publicly traded partnership. General and
administrative expenses related to being a publicly traded
partnership include expenses associated with annual and
quarterly reporting; tax return and
Schedule K-1
preparation and distribution expenses; Sarbanes-Oxley compliance
expenses; expenses associated with listing on NASDAQ;
independent auditor fees; legal fees; investor relations
expenses; registrar and transfer agent fees; director and
officer liability insurance costs and director compensation.
Adjusted
EBITDA
We define Adjusted EBITDA as net income (loss):
|
|
|
|
|
Interest expense, including realized and unrealized losses on
interest rate derivative contracts;
|
|
|
|
Income tax expense;
|
|
|
|
Depreciation, depletion and amortization;
|
|
|
|
Impairment of goodwill and long-lived assets (including oil and
natural gas properties);
|
|
|
|
Accretion of asset retirement obligations;
|
|
|
|
Unrealized losses on commodity derivative contracts;
|
|
|
|
Losses on sale of assets and other, net;
|
|
|
|
Unit-based compensation expenses;
|
|
|
|
Exploration costs; and
|
|
|
|
Other non-routine items that we deem appropriate.
|
104
|
|
|
|
|
Interest income;
|
|
|
|
Income tax benefit;
|
|
|
|
Unrealized gains on commodity derivative contracts;
|
|
|
|
Gains on sale of assets and other, net; and
|
|
|
|
Other non-routine items that we deem appropriate.
|
We expect that we will be required to comply with certain
Adjusted EBITDA-related metrics under our new revolving credit
facility.
Adjusted EBITDA will be used as a supplemental financial measure
by our management and by external users of our financial
statements, such as investors, commercial banks and others, to
assess:
|
|
|
|
|
our operating performance as compared to that of other companies
and partnerships in our industry, without regard to financing
methods, capital structure or historical cost basis; and
|
|
|
|
the ability of our assets to generate cash sufficient to pay
interest costs, support our indebtedness, and make distributions
on our units.
|
In addition, our management will use Adjusted EBITDA to evaluate
actual cash flow available to pay distributions to our
unitholders, develop existing reserves, or acquire additional
oil and natural gas properties. We expect that we will be
required to comply with certain Adjusted EBITDA-related metrics
under our new revolving credit facility. Adjusted EBITDA should
not be considered an alternative to net income, operating
income, cash flow from operating activities, or any other
measure of financial performance or liquidity presented in
accordance with GAAP. Our Adjusted EBITDA may not be comparable
to similarly titled measures of another company because all
companies may not calculate Adjusted EBITDA in the same manner.
For further discussion, please read Summary
Non-GAAP Financial Measure.
Outlook
Beginning in the second half of 2008, the United States and
other industrialized countries experienced a significant
economic slowdown, which led to a substantial decline in
worldwide energy demand. During this same period, North American
natural gas supply was increasing as a result of the rise in
domestic unconventional natural gas production. The combination
of lower energy demand due to the economic slowdown and higher
North American natural gas supply resulted in significant
declines in oil, NGL and natural gas prices. While oil and NGL
prices have increased since the second quarter of 2009, natural
gas prices remained volatile throughout 2010 and have remained
low in 2011, relative to much of 2007, 2008 and 2009, due to a
continued increase in natural gas supply despite weaker
offsetting demand growth. The outlook for a worldwide economic
recovery remains uncertain for the foreseeable future, and the
timing of a recovery in worldwide demand for energy is difficult
to predict. As a result, it is likely that commodity prices will
continue to be volatile for the remainder of 2011 and 2012.
Sustained periods of low prices for oil or natural gas could
materially and adversely affect our financial position, our
results of operations, the quantities of oil and natural gas
reserves that we can economically produce and our access to
capital.
Significant factors that may impact future commodity prices
include the political and economic developments currently
impacting Egypt, Libya and the Middle East in general; the
extent to which members of the Organization of Petroleum
Exporting Countries and other oil exporting nations are able to
continue to manage oil supply through export quotas; and overall
North American oil and natural gas supply and demand
fundamentals. Although we cannot predict the occurrence of
events that will affect future commodity prices or the degree to
which these prices will be affected, the prices for any oil,
natural gas or NGLs that we produce will generally approximate
market prices in the geographic region of the production.
105
As an oil and natural gas company, we face the challenge of
natural production declines. As initial reservoir pressures are
depleted, oil and natural gas production from a given well or
formation decreases. Our future growth will depend on our
ability to continue to add estimated reserves in excess of our
production. Accordingly, we plan to maintain our focus on adding
reserves through acquisitions and development projects and
improving the economics of producing oil and natural gas from
the Partnership Properties. We expect these acquisition
opportunities may come from Memorial Resource, the Funds, and
their respective affiliates, as well as from unrelated third
parties. Our ability to add estimated reserves through
acquisitions and development projects is dependent on many
factors, including our ability to raise capital, obtain
regulatory approvals and procure contract drilling rigs and
personnel.
106
Historical
and Pro Forma Financial and Operating Data
The following table sets forth selected historical combined
financial and operating data of our predecessor and unaudited
pro forma financial and operating data for Memorial Production
Partners LP for the periods presented. The following table
should be read in conjunction with Selected Historical and
Pro Forma Financial Data.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our Predecessor
|
|
|
Memorial Production Partners LP Pro Forma
|
|
|
|
|
|
|
Three
|
|
|
|
|
|
Three
|
|
|
|
|
|
|
Months
|
|
|
|
|
|
Months
|
|
|
|
|
|
|
Ended
|
|
|
Year Ended
|
|
|
Ended
|
|
|
|
Year Ended December 31,
|
|
|
March 31,
|
|
|
December 31,
|
|
|
March 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2010
|
|
|
2011
|
|
|
2010
|
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
$
|
49,313
|
|
|
$
|
24,541
|
|
|
$
|
37,308
|
|
|
$
|
7,879
|
|
|
$
|
11,641
|
|
|
$
|
87,762
|
|
|
$
|
20,648
|
|
Other income
|
|
|
622
|
|
|
|
319
|
|
|
|
1,433
|
|
|
|
67
|
|
|
|
103
|
|
|
|
1,404
|
|
|
|
99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
49,935
|
|
|
$
|
24,860
|
|
|
$
|
38,741
|
|
|
$
|
7,946
|
|
|
$
|
11,744
|
|
|
$
|
89,166
|
|
|
$
|
20,747
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
8,843
|
|
|
|
11,207
|
|
|
|
13,974
|
|
|
|
2,220
|
|
|
|
5,170
|
|
|
|
23,052
|
|
|
|
6,685
|
|
Exploration
|
|
|
374
|
|
|
|
2,690
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
Production and ad valorem taxes
|
|
|
3,127
|
|
|
|
1,464
|
|
|
|
2,112
|
|
|
|
509
|
|
|
|
693
|
|
|
|
7,387
|
|
|
|
1,703
|
|
Depreciation, depletion and amortization
|
|
|
12,353
|
|
|
|
15,226
|
|
|
|
20,066
|
|
|
|
4,352
|
|
|
|
4,450
|
|
|
|
34,772
|
|
|
|
7,026
|
|
Impairment of proved oil and natural gas properties
|
|
|
14,166
|
|
|
|
3,480
|
|
|
|
11,800
|
|
|
|
1,691
|
|
|
|
|
|
|
|
9,509
|
|
|
|
|
|
General and administrative
|
|
|
3,835
|
|
|
|
4,811
|
|
|
|
6,116
|
|
|
|
1,108
|
|
|
|
1,474
|
|
|
|
5,819
|
|
|
|
1,399
|
|
Accretion
|
|
|
224
|
|
|
|
320
|
|
|
|
663
|
|
|
|
64
|
|
|
|
210
|
|
|
|
1,072
|
|
|
|
276
|
|
(Gain) loss on derivative instruments
|
|
|
(9,815
|
)
|
|
|
(10,834
|
)
|
|
|
(10,264
|
)
|
|
|
(6,636
|
)
|
|
|
703
|
|
|
|
(10,264
|
)
|
|
|
703
|
|
Gain on sale of properties
|
|
|
(7,395
|
)
|
|
|
(7,851
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
|
|
|
|
304
|
|
|
|
890
|
|
|
|
|
|
|
|
|
|
|
|
890
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
25,712
|
|
|
|
20,817
|
|
|
|
45,395
|
|
|
|
3,308
|
|
|
|
12,692
|
|
|
|
72,273
|
|
|
|
17,792
|
|
Operating income (loss)
|
|
|
24,223
|
|
|
|
4,043
|
|
|
|
(6,654
|
)
|
|
|
4,638
|
|
|
|
(948
|
)
|
|
|
16,893
|
|
|
|
2,955
|
|
Interest expense
|
|
|
(3,138
|
)
|
|
|
(2,937
|
)
|
|
|
(4,438
|
)
|
|
|
(606
|
)
|
|
|
(1,035
|
)
|
|
|
(4,365
|
)
|
|
|
(1,092
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
21,085
|
|
|
|
1,106
|
|
|
|
(11,092
|
)
|
|
|
4,032
|
|
|
|
(1,983
|
)
|
|
|
12,528
|
|
|
|
1,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
(225
|
)
|
|
|
|
|
|
|
|
|
|
|
(225
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
21,085
|
|
|
$
|
1,106
|
|
|
$
|
(11,317
|
)
|
|
$
|
4,032
|
|
|
$
|
(1,983
|
)
|
|
$
|
12,303
|
|
|
$
|
1,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenue (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
5,886
|
|
|
$
|
3,521
|
|
|
$
|
3,438
|
|
|
$
|
740
|
|
|
$
|
1,472
|
|
|
$
|
7,933
|
|
|
$
|
2,539
|
|
NGL sales
|
|
|
1,559
|
|
|
|
924
|
|
|
|
1,404
|
|
|
|
345
|
|
|
|
278
|
|
|
|
10,177
|
|
|
|
2,434
|
|
Natural gas sales
|
|
|
41,868
|
|
|
|
20,096
|
|
|
|
32,466
|
|
|
|
6,794
|
|
|
|
9,891
|
|
|
|
69,652
|
|
|
|
15,675
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and natural gas revenue
|
|
$
|
49,313
|
|
|
$
|
24,541
|
|
|
$
|
37,308
|
|
|
$
|
7,879
|
|
|
$
|
11,641
|
|
|
$
|
87,762
|
|
|
$
|
20,648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
59
|
|
|
|
61
|
|
|
|
45
|
|
|
|
10
|
|
|
|
16
|
|
|
|
107
|
|
|
|
28
|
|
NGLs (MBbls)
|
|
|
83
|
|
|
|
33
|
|
|
|
34
|
|
|
|
8
|
|
|
|
5
|
|
|
|
272
|
|
|
|
56
|
|
Natural gas (MMcf)
|
|
|
4,719
|
|
|
|
5,282
|
|
|
|
7,314
|
|
|
|
1,224
|
|
|
|
2,266
|
|
|
|
16,713
|
|
|
|
3,897
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
5,569
|
|
|
|
5,847
|
|
|
|
7,792
|
|
|
|
1,330
|
|
|
|
2,395
|
|
|
|
18,985
|
|
|
|
4,399
|
|
Average net production (MMcfe/d)
|
|
|
15.2
|
|
|
|
16.0
|
|
|
|
21.3
|
|
|
|
14.8
|
|
|
|
26.6
|
|
|
|
52.0
|
|
|
|
48.8
|
|
Average sales price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
100.58
|
|
|
$
|
58.01
|
|
|
$
|
75.81
|
|
|
$
|
74.33
|
|
|
$
|
91.28
|
|
|
$
|
74.35
|
|
|
$
|
90.11
|
|
NGLs (per Bbl)
|
|
$
|
18.76
|
|
|
$
|
27.61
|
|
|
$
|
41.02
|
|
|
$
|
44.30
|
|
|
$
|
52.09
|
|
|
$
|
37.41
|
|
|
$
|
43.76
|
|
Natural gas (per Mcf)
|
|
$
|
8.87
|
|
|
$
|
3.80
|
|
|
$
|
4.44
|
|
|
$
|
5.55
|
|
|
$
|
4.36
|
|
|
$
|
4.17
|
|
|
$
|
4.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (per Mcfe)
|
|
$
|
8.86
|
|
|
$
|
4.20
|
|
|
$
|
4.79
|
|
|
$
|
5.92
|
|
|
$
|
4.86
|
|
|
$
|
4.62
|
|
|
$
|
4.69
|
|
Average unit costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.59
|
|
|
$
|
1.92
|
|
|
$
|
1.79
|
|
|
$
|
1.67
|
|
|
$
|
2.16
|
|
|
$
|
1.21
|
|
|
$
|
1.52
|
|
Production and ad valorem taxes
|
|
$
|
0.56
|
|
|
$
|
0.25
|
|
|
$
|
0.27
|
|
|
$
|
0.38
|
|
|
$
|
0.29
|
|
|
$
|
0.39
|
|
|
$
|
0.39
|
|
General and administrative expenses
|
|
$
|
0.69
|
|
|
$
|
0.82
|
|
|
$
|
0.78
|
|
|
$
|
0.83
|
|
|
$
|
0.62
|
|
|
$
|
0.31
|
|
|
$
|
0.32
|
|
Depreciation, depletion and amortization
|
|
$
|
2.22
|
|
|
$
|
2.60
|
|
|
$
|
2.58
|
|
|
$
|
3.27
|
|
|
$
|
1.86
|
|
|
$
|
1.83
|
|
|
$
|
1.60
|
|
107
Background
Information Regarding Our Predecessor, the Partnership
Properties, and Related Financial Data
The Partnership Properties consist of properties that will be
contributed to us by our predecessor (which consists of the
combined financial data of (a) BlueStone Natural Resources
Holdings, LLC, (b) certain oil and natural gas properties owned
by Classic Hydrocarbons Holdings, L.P., and (c) for periods
after April 8, 2011, certain oil and natural gas properties
owned by WHT Energy Partners LLC (WHT), each subsidiaries of
Memorial Resource). The properties being contributed to us by
our predecessor include (1) properties acquired by our
predecessor from Forest Oil Corporation (Forest Oil) in June
2010 (with respect to which certain financial statements are
included elsewhere in this prospectus), (2) properties acquired
by our predecessor from BP America Production Company (BP) in
May 2011 (with respect to which certain financial statements are
included elsewhere in this prospectus) and (3) a 40% undivided
interest in the properties acquired by WHT in April 2011 (with
respect to which certain financial statements are included
elsewhere in this prospectus).
Pro Forma
Results of Operations
Factors
Affecting the Comparability of the Pro Forma Results of Our
Partnership to the Historical Financial Results of Our
Predecessor
Our pro forma results of operations and our future results of
operations may not be comparable to the historical results of
operations of our predecessor for the periods presented,
primarily for the reasons described below:
|
|
|
|
|
Our predecessor completed its acquisition of certain properties
from Forest Oil in June 2010. Prior to such time, the estimated
proved reserves associated with and the results of operations
from those acquired assets were not included in our
predecessors results of operations prior to the date of
acquisition. The Forest Oil properties acquired by our
predecessor are included in the Partnership Properties and
represent 50 Bcfe, or approximately 15% of our pro forma
total estimated proved reserves, as of December 31, 2010.
|
|
|
|
Our predecessor completed its acquisition of certain properties
from BP in May 2011. The estimated proved reserves associated
with and the results of operations from those acquired assets
were not included in our predecessors historical results
of operations through May 31, 2011. The BP America
properties acquired by our predecessor are included in the
Partnership Properties and represent 47 Bcfe, or
approximately 15% of our pro forma total estimated proved
reserves, as of December 31, 2010.
|
|
|
|
The Partnership Properties will include property interests
contributed to us by WHT, all of which property interests were
acquired by WHT in April 2011. Those properties being
contributed represent 113 Bcfe, or approximately 35% of our
pro forma total estimated proved reserves, as of
December 31, 2010.
|
|
|
|
Our predecessor pays a management fee to the Funds pursuant to
its operating agreement. We are not obligated to pay such a
management fee, and therefore our pro forma results of
operations are not directly comparable to our predecessors
with respect to this fee.
|
|
|
|
Our predecessor uses commodity derivative contracts to manage
price fluctuations. Upon the closing of this offering, we will
enter into derivative contracts to manage price fluctuations and
our predecessor will contribute to us certain commodity
derivative contracts entered into in connection with its
ownership of the Partnership Properties, which will not comprise
all commodity derivative contracts entered into by our
predecessor.
|
Pro Forma
Liquidity and Capital Resources
We expect that our primary sources of liquidity and capital
resources after the consummation of the offering will be cash
flows generated by operating activities and borrowings under the
new revolving credit facility that we intend to enter into
concurrently with the closing of this offering. We may also have
the ability to issue additional equity and debt as needed.
108
We plan to enter into hedging arrangements to reduce the impact
of commodity price volatility on our cash flow from operations.
Under this strategy, we intend to enter into commodity
derivative contracts at times and on terms desired to maintain a
portfolio of commodity derivative contracts covering
approximately 65% to 85% of our estimated production from total
proved developed producing reserves over a
three-to-five
year period at a given point in time, although we may from time
to time hedge more or less than this approximate range.
Our partnership agreement requires that we distribute all of our
available cash (as defined in the partnership agreement) to our
unitholders and the general partner. In making cash
distributions, our general partner will attempt to avoid large
variations in the amount we distribute from quarter to quarter.
In order to facilitate this, our partnership agreement will
permit our general partner to establish cash reserves to be used
to pay distributions for any one or more of the next four
quarters. In addition, our partnership agreement allows our
general partner to borrow funds to make distributions.
We may borrow to make distributions to our unitholders, for
example, in circumstances where we believe that the distribution
level is sustainable over the long-term, but short-term factors
have caused available cash from operations to be insufficient to
sustain our level of distributions. In addition, we plan to
hedge a significant portion of our production. We generally will
be required to settle our commodity hedge derivatives within
five days of the end of the month. As is typical in the oil and
natural gas industry, we do not generally receive the proceeds
from the sale of our hedged production until 45 to 60 days
following the end of the month. As a result, when commodity
prices increase above the fixed price in the derivative
contracts, we will be required to pay the derivative
counterparty the difference between the fixed price in the
derivative contract and the market price before we receive the
proceeds from the sale of the hedged production. If this occurs,
we may make working capital borrowings to fund our
distributions. Because we will distribute all of our available
cash, we will not have those amounts available to reinvest in
our business to increase our proved reserves and production and
as a result, we may not grow as quickly as other oil and natural
gas entities or at all.
We plan to reinvest a sufficient amount of our cash flow in
acquisitions and development projects in order to maintain our
production and proved reserves, and we plan to use external
financing sources to increase our production and proved
reserves. Because our proved reserves and production decline
continually over time and because we own a limited amount of
undeveloped properties, we may need to make acquisitions to
sustain our level of distributions to unitholders over time.
If cash flow from operations does not meet our expectations, we
may reduce our expected level of capital expenditures, reduce
distributions to unitholders,
and/or fund
a portion of our capital expenditures using borrowings under our
new revolving credit facility, issuances of debt and equity
securities or from other sources, such as asset sales. We cannot
assure you that needed capital will be available on acceptable
terms or at all. Our ability to raise funds through the
incurrence of additional indebtedness could be limited by the
covenants in our new revolving credit facility. If we are unable
to obtain funds when needed or on acceptable terms, we may not
be able to complete acquisitions that may be favorable to us or
finance the capital expenditures necessary to maintain our
production or proved reserves.
Capital
Expenditures
Maintenance capital expenditures are capital expenditures that
we expect to make on an ongoing basis to maintain our production
and asset base (including our undeveloped leasehold acreage).
The primary purpose of maintenance capital is to maintain our
production and asset base at a steady level over the long term
to maintain our distributions per unit. For the twelve months
ending June 30, 2012, we estimate that our maintenance
capital expenditures will be approximately $9.2 million,
which amount spent annually we believe will enable us to
maintain our targeted average net production from our assets of
49 MMcfe/d through December 31, 2015.
Growth capital expenditures are capital expenditures that we
expect to increase our production and the size of our asset
base. The primary purpose of growth capital is to acquire
producing assets that will increase our distributions per unit
and secondarily increase the rate of development and production
of our existing properties in a manner which is expected to be
accretive to our unitholders. Growth capital expenditures on
existing properties may
109
include projects on our existing asset base, like horizontal
re-entry programs that increase the rate of production and
provide new areas of future reserve growth. Although we may make
acquisitions during the twelve months ending June 30, 2012,
including potential acquisitions of producing properties from
Memorial Resource, we have not estimated any growth capital
expenditures related to acquisitions, as we cannot be certain
that we will be able to identify attractive properties or, if
identified, that we will be able to negotiate acceptable
purchase contracts.
The amount and timing of our capital expenditures is largely
discretionary and within our control, with the exception of
certain projects managed by other operators. If oil and natural
gas prices decline below levels we deem acceptable, we may defer
a portion of our planned capital expenditures until later
periods. Accordingly, we routinely monitor and adjust our
capital expenditures in response to changes in oil and natural
gas prices, drilling and acquisition costs, industry conditions
and internally generated cash flow. Matters outside of our
control that could affect the timing of our capital expenditures
include obtaining required permits and approvals in a timely
manner and the availability of rigs and labor crews. Based on
our current oil and natural gas price expectations, we
anticipate that our cash flow from operations and available
borrowing capacity under our new revolving credit facility will
exceed our planned capital expenditures and other cash
requirements for the twelve months ending June 30, 2012.
However, future cash flows are subject to a number of variables,
including the level of our oil and natural gas production and
the prices we receive for our oil and natural gas production,
generally. There can be no assurance that our operations and
other capital resources will provide cash in amounts that are
sufficient to maintain our planned levels of capital
expenditures.
New
Revolving Credit Facility
Concurrently with the closing of this offering, we anticipate
that we will enter into a new revolving credit facility, which
we expect to be a multi-year,
$ million revolving credit
facility with an initial borrowing base of approximately
$ million.
We anticipate that our new revolving credit facility will be
reserve-based, and thus we will be permitted to borrow under our
new revolving credit facility in an amount up to the borrowing
base, which is primarily based on the estimated value of our oil
and natural gas properties and our commodity derivative
contracts as determined semi-annually by our lenders in their
sole discretion. Our borrowing base will be subject to
redetermination on a semi-annual basis based on an engineering
report with respect to our estimated natural gas, NGL and oil
reserves, which will take into account the prevailing natural
gas, NGL and oil prices at such time, as adjusted for the impact
of our commodity derivative contracts. In the future, we may be
unable to access sufficient capital under our new revolving
credit facility as a result of (i) a decrease in our
borrowing base due to a subsequent borrowing base
redetermination, or (ii) an unwillingness or inability on
the part of our lenders to meet their funding obligations.
A future decline in commodity prices could result in a
redetermination that lowers our borrowing base in the future
and, in such case, we could be required to repay any
indebtedness in excess of the borrowing base, or we could be
required to pledge other oil and natural gas properties as
additional collateral. We do not anticipate having any
substantial unpledged properties, and we may not have the
financial resources in the future to make any mandatory
principal prepayments required under our new revolving credit
facility. Additionally, we anticipate that if, at the time of
any distribution, our borrowings equal or exceed the maximum
percentage allowed of the then-specified borrowing base, we will
not be able to pay distributions to our unitholders in any such
quarter without first making the required repayments of
indebtedness under our new revolving credit facility.
We also anticipate that our new revolving credit facility will
contain certain financial tests and covenants that we must
satisfy.
Commodity
Derivative Contracts
Our cash flow from operations is subject to many variables, the
most significant of which is the volatility of oil and natural
gas prices. Oil and natural gas prices are determined primarily
by prevailing market conditions, which are dependent on regional
and worldwide economic activity, weather and other factors
beyond our control.
110
Our future cash flow from operations will depend on the prices
of oil and natural gas and our ability to maintain and increase
production through acquisitions and exploitation and development
projects.
We expect to adopt a hedging policy designed to reduce the
impact to our cash flows from commodity price volatility. Under
this policy, we intend to enter into commodity derivative
contracts covering approximately 65% to 85% of our estimated
production from total proved developed producing reserves over a
three-to-five
year period at any given point of time. We may, however, from
time to time hedge more or less than this approximate range.
Additionally, we intend to individually identify these
non-speculative hedges as designated hedges for
U.S. federal income tax purposes as we enter into them.
Memorial Resource will contribute to us at the closing of this
offering derivative contracts for the six months ending
December 31, 2011 and the years ending December 31,
2012, 2013, 2014, and 2015 covering approximately 76%, 75%, 69%,
14% and 8%, respectively, of our estimated production from our
total proved developed producing reserves existing as of
December 31, 2010, based on our reserve reports. Please
read Overview Realized Prices on
the Sale of Oil and Natural Gas Commodity Derivative
Contracts. These commodity derivative contracts limit our
exposure to declines in prices, but also limit the benefits if
prices increase. We do not specifically designate derivative
contracts as cash flow hedges; therefore, the
mark-to-market
adjustment reflecting the change in the unrealized gains or
losses on these contracts is recorded in current period
earnings. When prices for oil and natural gas are volatile, a
significant portion of the effect of our hedging activities
consists of non-cash income or expenses due to changes in the
fair value of our derivative contracts. Realized gains or losses
only arise from payments made or received on monthly settlements
or if a derivative contract is terminated prior to its
expiration.
Pro Forma
Quantitative and Qualitative Disclosure About Market
Risk
We are exposed to market risk, including the effects of adverse
changes in commodity prices and interest rates as described
below.
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about
our potential exposure to market risks. The term market
risk refers to the risk of loss arising from adverse
changes in oil and natural gas prices and interest rates. The
disclosures are not meant to be precise indicators of expected
future losses, but rather indicators of reasonably possible
losses. All of our market risk sensitive instruments were
entered into for purposes other than speculative trading.
Commodity
Price Risk
Our major market risk exposure is in the pricing that we receive
for our oil and natural gas production. Realized pricing is
primarily driven by the spot market prices applicable to our oil
and natural gas production. Pricing for oil and natural gas has
been volatile for several years, and we expect this volatility
to continue in the future. The prices we receive for our oil and
natural gas production depend on many factors outside of our
control, such as the strength of the global economy.
In order to reduce the impact of fluctuations in oil and natural
gas prices on our revenues, or to protect the economics of
property acquisitions, we intend to periodically enter into
derivative contracts with respect to a significant portion of
our estimated oil and natural gas production through various
transactions that fix the future prices received. These
transactions may include price swaps whereby we will receive a
fixed price for our production and pay a variable market price
to the contract counterparty. Additionally, we may enter into
collars, whereby we receive the excess, if any, of the fixed
floor over the floating rate or we pay the excess, if any, of
the floating rate over the fixed ceiling price. These hedging
activities are intended to support oil and natural gas prices at
targeted levels and to manage our exposure to oil and natural
gas price fluctuations.
Swaps. In a typical commodity swap
agreement, we receive the difference between a fixed price per
unit of production and a price based on an agreed upon published
third-party index, if the index price is lower than the fixed
price. If the index price is higher, we pay the difference. By
entering into swap agreements, we effectively fix the price that
we will receive in the future for the hedged production. Our
current swaps are settled in cash on a monthly basis.
111
Put Options. In a typical put option
arrangement, we receive the excess, if any, of the contract
floor price over the reference price, based on NYMEX quoted
prices. Our current put options are exercised in cash on a
monthly basis only when the floor price exceeds the reference
price, otherwise they expire unsettled.
Collars. In a typical collar
arrangement, we receive the excess, if any, of the contract
floor price over the reference price, based on NYMEX quoted
prices, and pay the excess, if any, of the reference price over
the contract ceiling price. Our current collars are exercised in
cash on a monthly basis only when the reference price is outside
of floor and ceiling prices (the collar), otherwise, they expire
unsettled.
Interest
Rate Risk
On a pro forma basis as of March 31, 2011, we had debt
outstanding of $130.0 million, with an assumed weighted
average interest rate of LIBOR plus 2.75%, or 3.05%. Assuming no
change in the amount outstanding, the impact on interest expense
of a 10% increase or decrease in the average interest rate would
be approximately $0.4 million. In the future, we anticipate
entering into interest rate derivative contracts on a portion of
our outstanding debt to mitigate the risk of fluctuations in
LIBOR.
Counterparty
and Customer Credit Risk
Joint interest receivables arise from entities which own partial
interests in the wells we operate. These entities participate in
our wells primarily based on their ownership in leases on which
we drill. We have limited ability to control participation in
our wells. We are also subject to credit risk due to the
concentration of our oil and natural gas receivables with
several significant customers. Please read Business and
Properties Operations Marketing and
Major Customers for further detail about our significant
customers. The inability or failure of our significant customers
to meet their obligations to us or their insolvency or
liquidation may adversely affect our financial results. In
addition, our oil and natural gas derivative contracts expose us
to credit risk in the event of nonperformance by counterparties.
While we do not plan to require our customers to post collateral
and do not intend to have a formal process in place to evaluate
and assess the credit standing of our significant customers or
the counterparties on our derivative contracts, we will evaluate
the credit standing of our customers and such counterparties as
we deem appropriate under the circumstances. This evaluation may
include reviewing a counterpartys credit rating and latest
financial information or, in the case of a customer with which
we have receivables, reviewing their historical payment record,
the financial ability of the customers parent company to
make payment if the customer cannot and undertaking the due
diligence necessary to determine credit terms and credit limits.
The counterparties on our derivative contracts currently in
place are lenders under our predecessors credit
facilities, with investment grade ratings and we are likely to
enter into any future derivative contracts with these or other
lenders under our new revolving credit facility that also carry
investment grade ratings. Several of our significant customers
for oil and natural gas receivables have a credit rating below
investment grade or do not have rated debt securities. In these
circumstances, we have considered the lack of investment grade
credit rating in addition to the other factors described above.
Predecessor
Results of Operations
Our predecessor consists of the combined financial data of
BlueStone Natural Resources Holdings, LLC, certain oil and
natural gas properties owned by Classic Hydrocarbons Holdings,
L.P. and for periods after April 8, 2011, certain oil and
natural gas properties owned by WHT. Our predecessor is not
contributing all of its properties to us, and the Partnership
Properties do not consist solely of the properties being
contributed by our predecessor.
Factors
Affecting the Comparability of the Historical Financial Results
of Our Predecessor.
The comparability of our predecessors results of
operations among the periods presented is impacted by:
|
|
|
|
|
The following significant acquisitions by our predecessor:
|
|
|
|
|
|
The Forest Oil asset acquisition in June 2010 for approximately
$65.9 million.
|
112
|
|
|
|
|
Two separate acquisitions of assets in East Texas in January and
March 2010, respectively, for a net purchase price of
approximately $14 million.
|
|
|
|
Two separate acquisitions of assets in South Texas in April and
May 2010, respectively, for a total purchase price of
approximately $23.2 million.
|
|
|
|
|
|
The sale of certain non-core oil and natural gas properties
located in South Texas in 2009 and 2008 for $11.8 million
and $15.4 million, respectively.
|
As a result of the factors listed above, historical results of
operations and
period-to-period
comparisons of these results and certain financial data may not
be comparable or indicative of future results.
Three
Months Ended March 31, 2010 Compared to the Three Months
Ended March 31, 2011
The following table summarizes key items of comparison and their
related increase (decrease) for the three months ended
March 31, 2010 and 2011 as indicated.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2011
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
$
|
7,879
|
|
|
$
|
11,641
|
|
Other income
|
|
|
67
|
|
|
|
103
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
7,946
|
|
|
|
11,744
|
|
Costs and expenses (in thousands):
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
2,220
|
|
|
|
5,170
|
|
Exploration
|
|
|
|
|
|
|
|
|
Production and ad valorem taxes
|
|
|
509
|
|
|
|
693
|
|
Depreciation, depletion and amortization
|
|
|
4,352
|
|
|
|
4,450
|
|
Impairment of proved oil and natural gas properties
|
|
|
1,691
|
|
|
|
|
|
General and administrative
|
|
|
1,108
|
|
|
|
1,474
|
|
Accretion
|
|
|
64
|
|
|
|
210
|
|
(Gain) loss on derivative instruments
|
|
|
(6,636
|
)
|
|
|
703
|
|
Gain on sale of properties
|
|
|
|
|
|
|
(8
|
)
|
Other, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
3,308
|
|
|
|
12,692
|
|
Operating income (loss)
|
|
|
4,638
|
|
|
|
(948
|
)
|
Interest expense
|
|
|
(606
|
)
|
|
|
(1,035
|
)
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
4,032
|
|
|
$
|
(1,983
|
)
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
10
|
|
|
|
16
|
|
NGLs (MBbls)
|
|
|
8
|
|
|
|
5
|
|
Natural gas (MMcf)
|
|
|
1,224
|
|
|
|
2,266
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
1,330
|
|
|
|
2,395
|
|
Average net production (MMcfe/d)
|
|
|
14.8
|
|
|
|
26.6
|
|
113
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
|
2010
|
|
|
2011
|
|
|
Average sales price:
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
74.33
|
|
|
$
|
91.28
|
|
NGLs (per Bbl)
|
|
$
|
44.30
|
|
|
$
|
52.09
|
|
Natural gas (per Mcf)
|
|
$
|
5.55
|
|
|
$
|
4.36
|
|
Total (per Mcfe)
|
|
$
|
5.92
|
|
|
$
|
4.86
|
|
Average unit costs per Mcfe:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.67
|
|
|
$
|
2.16
|
|
Production and ad valorem taxes
|
|
$
|
0.38
|
|
|
$
|
0.29
|
|
Depreciation, depletion and amortization
|
|
$
|
3.27
|
|
|
$
|
1.86
|
|
Impairment of proved oil and natural gas properties
|
|
$
|
1.27
|
|
|
$
|
|
|
General and administrative expenses
|
|
$
|
0.83
|
|
|
$
|
0.62
|
|
Our predecessor recorded net income of $4.0 million for the
three month period ended March 31, 2010 compared to a net
loss of $2.0 million for the three months ended
March 31, 2011. The three months ended March 31, 2010
included a $6.6 million gain on derivative instruments, as
compared to a $0.7 million loss during the same period in
2011.
Revenues. The oil and natural gas sales
revenues of our predecessor totaled $7.9 million for the
three months ended March 31, 2010, reflecting a 47%
increase to the $11.6 million in revenues generated during
the same period in 2011. The increase was due to an increase in
production of 1,065 MMcfe, or 80%, primarily related to the
acquisition of certain oil and natural gas assets from Forest
Oil and Merit Energy, effective April 2010 and May 2010,
respectively. The additional production from these acquisitions
was offset by lower average realized commodity prices, which
decreased from $5.92 per Mcfe for the three months ended
March 31, 2010 to $4.86 per Mcfe, or 18%, for the same
period in 2011.
Lease Operating. Lease operating
expenses increased from $2.2 million for the three months
ended March 31, 2010 to approximately $5.2 million for
the same period in 2011. The change was primarily due to the
increase in production volumes described above, as well as
workover costs associated with discovery and production
enhancements on previously shut-in wells acquired in 2010.
Workover costs also drove lease operating expenses per Mcfe up
30%, from $1.67 to $2.16 between the first quarter 2010 and same
period in 2011.
Production and Ad Valorem
Taxes. Production and ad valorem taxes
increased from $0.5 million for the three months ended
March 31, 2010 to $0.7 million for the same period in
2011 due to an increase in production revenues.
Depreciation, Depletion and
Amortization. Our predecessors
depreciation, depletion and amortization (DD&A) expense
increased only slightly from approximately $4.4 million in
the three months ended March 31, 2010 to $4.5 million
during the three months ended March 31, 2011, while
DD&A per Mcfe decreased from $3.27 to $1.86 between the
respective three month periods in 2010 and 2011, due to an
increase in proved reserve volumes between periods.
Impairment of Proved Oil and Natural Gas
Properties. Impairment of proved oil and
natural gas properties totaled $1.7 million for the three
months ended March 31, 2010, as compared to no impairments
incurred during the same time period in 2011. The property
impairment primarily pertained to economic factors such as the
results of exploration activities, commodity price outlooks,
remaining lease terms, and potential shifts in business strategy
employed by management.
General and Administrative. Our
predecessors general and administrative expenses totaled
$1.1 million and $1.5 million for the three months
ended March 31, 2010 and 2011, respectively. General and
administrative expenses include the costs of administrative
employees, related benefits, office rents, professional fees and
other costs not directly associated with field operations or
production. Accordingly, increased
period-over-period
production volumes drove general and administrative expenses
lower on a per
114
Mcfe basis from approximately $0.83 per Mcfe during the three
months ended March 31, 2010 to $0.62 per Mcfe for the three
months ended March 31, 2011.
(Gain) Loss on Derivative
Instruments. Our predecessor recognized a
gain on derivative instruments of $6.6 million in 2010,
compared to a loss of $0.7 million generated during the
same period in 2011. The decrease in derivative income was due
to an increase in forward commodity prices related to unrealized
hedges between the respective periods.
Interest Expense. Our
predecessors interest expense is comprised of interest on
its credit facilities and amortization of debt issuance costs.
Interest expense totaled $0.6 million for the three months
ended March 31, 2010 as compared to $1.0 million for
the three months ended March 31, 2011. This increase was
due primarily to additional debt incurred in conjunction with
acquisitions of certain oil and natural gas properties from
Forest Oil in the second quarter of 2010.
115
Year
Ended December 31, 2009 Compared to the Year Ended
December 31, 2010
The following table summarizes key items of comparison and their
related increase (decrease) for the years ended
December 31, 2009 and 2010 as indicated.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2010
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
$
|
24,541
|
|
|
$
|
37,308
|
|
Other income
|
|
|
319
|
|
|
|
1,433
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
24,860
|
|
|
|
38,741
|
|
Costs and expenses (in thousands):
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
11,207
|
|
|
|
13,974
|
|
Exploration
|
|
|
2,690
|
|
|
|
39
|
|
Production and ad valorem taxes
|
|
|
1,464
|
|
|
|
2,112
|
|
Depreciation, depletion and amortization
|
|
|
15,226
|
|
|
|
20,066
|
|
Impairment of proved oil and natural gas properties
|
|
|
3,480
|
|
|
|
11,800
|
|
General and administrative
|
|
|
4,811
|
|
|
|
6,116
|
|
Accretion
|
|
|
320
|
|
|
|
663
|
|
(Gain) loss on derivative instruments
|
|
|
(10,834
|
)
|
|
|
(10,264
|
)
|
Gain on sale of properties
|
|
|
(7,851
|
)
|
|
|
(1
|
)
|
Other, net
|
|
|
304
|
|
|
|
890
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
20,817
|
|
|
|
45,395
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
4,043
|
|
|
|
(6,654
|
)
|
Interest expense
|
|
|
(2,937
|
)
|
|
|
(4,438
|
)
|
Income (loss) before taxes
|
|
|
1,106
|
|
|
|
(11,092
|
)
|
Income tax expense
|
|
|
|
|
|
|
(225
|
)
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
1,106
|
|
|
$
|
(11,317
|
)
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
61
|
|
|
|
45
|
|
NGLs (MBbls)
|
|
|
33
|
|
|
|
34
|
|
Natural gas (MMcf)
|
|
|
5,282
|
|
|
|
7,314
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
5,847
|
|
|
|
7,792
|
|
Average net production (MMcfe/d)
|
|
|
16
|
|
|
|
21
|
|
Average sales price:
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
58.01
|
|
|
$
|
75.81
|
|
NGLs (per Bbl)
|
|
$
|
27.61
|
|
|
$
|
41.02
|
|
Natural gas (per Mcf)
|
|
$
|
3.80
|
|
|
$
|
4.44
|
|
Total (per Mcfe)
|
|
$
|
4.20
|
|
|
$
|
4.79
|
|
Average unit cost per Mcfe:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.92
|
|
|
$
|
1.79
|
|
Production and ad valorem taxes
|
|
$
|
0.25
|
|
|
$
|
0.27
|
|
Depreciation, depletion and amortization
|
|
$
|
2.60
|
|
|
$
|
2.58
|
|
Impairment of proved oil and natural gas properties
|
|
$
|
0.60
|
|
|
$
|
1.51
|
|
General and administrative expenses
|
|
$
|
0.82
|
|
|
$
|
0.78
|
|
Our predecessor recorded net income of $1.1 million for the
year ended December 31, 2009 compared to a net loss of
$11.3 million generated during 2010. Despite a
$12.8 million increase in oil and natural gas sales
revenues between the periods, net income decreased approximately
$12.4 million primarily related to a
116
$4.8 million increase in DD&A, an $8.3 million
increase in impairment charges and a $7.9 million decrease
in gains on the sale of properties.
Revenues. Our predecessors oil
and natural gas sales revenues increased 52% from
$24.5 million for the year ended December 31, 2009 to
$37.3 million for the year ended December 31, 2010.
Approximately 70%, or $9.0 million, of this increase was
driven by increased production, which increased approximately
33% to 7,792 MMcfe for the year ended December 31,
2010. The remainder of the increase in revenues was due to
higher oil and natural gas commodity prices received, which
averaged $4.20 per Mcfe during 2009 and $4.79 per Mcfe during
2010. Other income revenues related to the predecessor
properties increased from $0.3 million for the year ended
December 31, 2009 to $1.4 million for the year ended
December 31, 2010, primarily due to the settlement of
litigation that occurred in 2010.
Lease Operating. Lease operating
expenses increased from $11.2 million for the year ended
December 31, 2009 to $14.0 million in 2010, primarily
as a result of the increase in our predecessors production
volumes described above. Lease operating expenses per Mcfe
decreased period to period approximately 6% from $1.92 per Mcfe
in 2009 to $1.79 per Mcfe in 2010, primarily related to the
increase in production.
Exploration. Exploration expenses
decreased from the $2.7 million incurred for the year ended
December 31, 2009 to less than $0.1 million in 2010,
primarily due to the reclassification of capitalized costs to
expense in 2009 following the evaluation of exploratory wells
previously drilled in 2008.
Production and Ad Valorem
Taxes. Production taxes increased from
$1.5 million in 2009 to $2.1 million in 2010, which is
consistent with higher oil and natural gas commodity prices
received during 2010 of $4.79 per Mcfe compared to $4.20 per
Mcfe during 2009.
Depreciation, Depletion and
Amortization. Our predecessors
DD&A expense increased from approximately
$15.2 million in 2009 to $20.1 million in 2010 as a
result of an increase in production volumes and the acquisition
of proved reserves during 2010.
Impairment of Proved Oil and Natural Gas
Properties. Impairment of proved oil and
natural gas properties totaled $3.5 million for 2009, as
compared to $11.8 million for 2010. The property
impairments primarily pertained to economic factors such as the
results of exploration activities, commodity price outlooks,
remaining lease terms, and potential shifts in business strategy
employed by management.
General and Administrative. Our
predecessors general and administrative expenses totaled
$4.8 million and $6.1 million for the years ended
December 31, 2009 and 2010, respectively. General and
administrative expenses include the costs of administrative
employees, related benefits, office rents, professional fees and
other costs not directly associated with field operations or
production. The change in general and administrative expenses
during 2010 resulted primarily from an increase of approximately
$0.5 million in payroll related costs and an increase of
approximately $0.6 million in professional services fees
paid.
Gain on Derivative Instruments. Our
predecessor recognized gains on derivative instruments of
$10.8 million in 2009, as compared to $10.3 million
generated in 2010. For 2009, the $10.8 million gain was
comprised of realized gains of $17.6 million and unrealized
losses of $6.8 million. For 2010, the $10.3 million
gain was comprised of realized gains of $7.3 million and
unrealized gains of $3.0 million.
Gain on Sale of Properties. During
2009, our predecessor recognized a gain of approximately
$7.8 million on two separate sales of interests in the
Nueces Mineral Company lease, located in South Texas and
primarily undeveloped, for net proceeds of $11.7 million.
Interest Expense. Interest expense
totaled $2.9 million in 2009 as compared to
$4.4 million in 2010. This increase was due primarily to
additional debt incurred in conjunction with acquisitions of
certain oil and natural gas assets from Forest Oil in the second
quarter of 2010.
117
Year
Ended December 31, 2008 Compared to the Year Ended
December 31, 2009
The following table summarizes key items of comparison and their
related increase (decrease) for the years ended
December 31, 2008 and 2009 as indicated.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
$
|
49,313
|
|
|
$
|
24,541
|
|
Other income
|
|
|
622
|
|
|
|
319
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
49,935
|
|
|
|
24,860
|
|
Costs and expenses (in thousands):
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
8,843
|
|
|
|
11,207
|
|
Exploration
|
|
|
374
|
|
|
|
2,690
|
|
Production and ad valorem taxes
|
|
|
3,127
|
|
|
|
1,464
|
|
Depreciation, depletion and amortization
|
|
|
12,353
|
|
|
|
15,226
|
|
Impairment of proved oil and natural gas properties
|
|
|
14,166
|
|
|
|
3,480
|
|
General and administrative
|
|
|
3,835
|
|
|
|
4,811
|
|
Accretion
|
|
|
224
|
|
|
|
320
|
|
(Gain) loss on derivative instruments
|
|
|
(9,815
|
)
|
|
|
(10,834
|
)
|
Gain on sale of properties
|
|
|
(7,395
|
)
|
|
|
(7,851
|
)
|
Other, net
|
|
|
|
|
|
|
304
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
25,712
|
|
|
|
20,817
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
24,223
|
|
|
|
4,043
|
|
Interest expense
|
|
|
(3,138
|
)
|
|
|
(2,937
|
)
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
21,085
|
|
|
$
|
1,106
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
59
|
|
|
|
61
|
|
NGLs (MBbls)
|
|
|
83
|
|
|
|
33
|
|
Natural gas (MMcf)
|
|
|
4,719
|
|
|
|
5,282
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
5,569
|
|
|
|
5,847
|
|
Average net production (MMcfe/d)
|
|
|
15
|
|
|
|
16
|
|
Average sales price:
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
100.58
|
|
|
$
|
58.01
|
|
NGLs (per Bbl)
|
|
$
|
18.76
|
|
|
$
|
27.61
|
|
Natural gas (per Mcf)
|
|
$
|
8.87
|
|
|
$
|
3.80
|
|
Total (per Mcfe)
|
|
$
|
8.86
|
|
|
$
|
4.20
|
|
Average unit costs per Mcfe:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.59
|
|
|
$
|
1.92
|
|
Production and ad valorem taxes
|
|
$
|
0.56
|
|
|
$
|
0.25
|
|
Depreciation, depletion and amortization
|
|
$
|
2.22
|
|
|
$
|
2.60
|
|
Impairment of proved oil and natural gas properties
|
|
$
|
2.54
|
|
|
$
|
0.60
|
|
General and administrative expenses
|
|
$
|
0.69
|
|
|
$
|
0.82
|
|
Our predecessor recorded net income of $21.1 million for
the year ended December 31, 2008 compared to net income of
$1.1 million for 2009. This decrease in net income was
driven by a $24.8 million
year-over-year
decline in oil and natural gas sales revenues as a result of
significant declines in commodity prices received for oil and
natural gas production.
Revenues. Our predecessors oil
and natural gas sales revenues totaled $49.3 million in
2008, reflecting a 50% decline to the $24.5 million in
revenues generated during the same period in 2009. Although
overall production levels increased on a Mcfe basis by 7% from
the twelve months ended December 31, 2008 to the
118
same period in 2009, average commodity prices decreased from
$8.86 per Mcfe to $4.20 per Mcfe between the respective periods.
Lease Operating. Lease operating
expenses increased from $8.8 million incurred in 2008 to
$11.2 million in 2009 primarily as a result of the increase
in production volumes and wells operated described above.
Overall, lease operating expenses increased 21% from $1.59 per
Mcfe during 2008 to $1.92 per Mcfe during 2009.
Exploration. Exploration expenses
increased from $0.4 million incurred in 2008 to
$2.7 million in 2009 primarily due to the reclassification
of capitalized costs to expense in 2009 following the evaluation
of exploratory wells previously drilled in 2008.
Production and Ad Valorem
Taxes. Production taxes declined from
$3.1 million, or $0.56 per Mcfe, in 2008 to
$1.5 million, or $0.25 per Mcfe, in 2009 due to the
decrease in oil and natural gas sales revenues noted above and
also due to tax refunds received and accounted for in 2009,
which were for allowable tax credits and tax deductions.
Depreciation, Depletion and
Amortization. Our predecessors
depreciation, depletion and amortization expense increased from
approximately $12.4 million in 2008 to $15.2 million
in 2009 due to a slight increase in volumes, and a resulting 17%
increase in the DD&A rate from $2.22 to $2.60 per Mcfe. The
increase in the DD&A rate was driven by additional
acquisition costs in 2009.
Impairment of Proved Oil and Natural Gas
Properties. Impairment of proved oil and
natural gas properties totaled $14.2 million for 2008, as
compared to $3.5 million incurred in 2009. The property
impairments primarily resulted from the dramatic decline in oil
prices during 2008.
General and Administrative. Our
predecessors general and administrative expenses totaled
$3.8 million and $4.8 million for 2008 and 2009,
respectively. The increase in general and administrative
expenses during 2009 resulted primarily from payroll related
costs.
Gain on Derivative Instruments. Our
predecessor recognized gains on derivative instruments of
$9.8 million in 2008 as compared to $10.8 million in
2009, For 2008, the $9.8 million gain was comprised of
$10.3 million of unrealized gains and realized losses of
$0.5 million. For 2009, the $10.8 million gain was
comprised of realized gains of $17.6 million and unrealized
losses of $6.8 million.
Interest Expense. Interest expense
remained fairly constant between periods, with $3.1 million
incurred in 2008 as compared to $2.9 million in 2009.
Predecessor
Liquidity and Capital Resources
Our predecessors primary sources of capital and liquidity
have been proceeds from bank borrowings, capital contributions
from the partners of its limited partnerships and cash flow from
operations. To date, our predecessors primary use of
capital has been for the acquisition and development of oil and
natural gas properties.
Predecessor
Cash Flows
Cash flows provided by operating activities were primarily used
to fund exploration and development expenditures. Proceeds from
the issuance of long-term debt and cash received from operations
in both years were offset by cash used in investing activities
to complete our acquisition activities. Operating cash flow
fluctuations were substantially driven by commodity prices and
changes in our production volumes. Prices for oil and natural
gas have historically been subject to seasonal influences
characterized by peak demand and higher prices in the winter
heating season; however, the impact of other risks and
uncertainties have influenced prices throughout recent years.
Working capital was substantially influenced by these variables.
Fluctuation in cash flow may result in an increase or decrease
in our capital and exploration expenditures.
119
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Three Months Ended March 31,
|
|
|
2008
|
|
2009
|
|
2010
|
|
2010
|
|
2011
|
|
Net cash provided by operating activities
|
|
$
|
32,838
|
|
|
$
|
12,672
|
|
|
$
|
20,288
|
|
|
$
|
3,935
|
|
|
$
|
2,999
|
|
Net cash used in investing activities
|
|
|
(45,547
|
)
|
|
|
(24,947
|
)
|
|
|
(116,687
|
)
|
|
|
(10,601
|
)
|
|
|
(7,898
|
)
|
Net cash provided by financing activities
|
|
|
11,619
|
|
|
|
15,989
|
|
|
|
96,756
|
|
|
|
9,434
|
|
|
|
1,375
|
|
Net (decrease) increase in cash
|
|
|
(1,090
|
)
|
|
|
3,714
|
|
|
|
357
|
|
|
|
2,768
|
|
|
|
(3,524
|
)
|
Operating Activities. Key drivers of
net operating cash flows are commodity prices, production
volumes and operating costs. Net cash flows provided by
operating activities increased for the year ended
December 31, 2010, despite a decrease in net income,
primarily due to our increase in production volumes as a result
of our acquisition activities as well as our continued drilling
success. Net cash flows provided by operating activities for the
year ended December 31, 2009 decreased from the year ended
December 31, 2008, driven primarily by lower net income.
Net cash flows provided by operating activities decreased from
the three months ended March 31, 2010 to the three months
ended March 31, 2011, driven by a decrease in net income,
offset by an unrealized loss on derivative instruments recorded
in 2011 compared to an unrealized gain on derivative instruments
recorded in 2010.
Investing Activities. During 2010, our
predecessor spent $104.5 million on several acquisitions,
the largest of which was the purchase of oil and natural gas
properties from Forest Oil for $65.9 million. Our
predecessor incurred capital expenditures of $13.1 million
in conjunction with the drilling of 6 wells in 2010, none
of which were dry holes, for a success rate of 100%. Our
predecessors acquisition and development expenditures were
offset by proceeds from the sale of properties for
$1.4 million.
Cash used in investing activities was $24.9 million in
2009. Acquisitions of oil and natural gas properties in South
Texas were largely offset by the proceeds from divestitures in
the Rocky Mountain, Mid-Continent and Gulf Coast. During 2009,
our predecessor participated in the drilling of 6 wells,
none of which were dry holes, for a success rate of 100%.
Cash used in investing activities in 2008 was
$45.5 million. Acquisitions of oil and natural gas
properties in the Laredo area were largely offset by the
proceeds from divestitures in South Texas. During 2008, our
predecessor participated in the drilling of 22 wells, of
which 5 were dry holes, for a success rate of 77%.
Cash used in investing activities for the three months ended
March 31, 2011 was $7.9 million, driven mostly by
additions to oil and natural gas properties of
$6.0 million. During the three months ended March 31,
2011, our predecessor participated in the drilling of
2 wells, none of which were dry holes, for a success rate
of 100%.
Cash used in investing activities for the three months ended
March 31, 2010 was $10.6 million, driven mostly by
acquisition activity in March of 2010 when oil and natural gas
properties were acquired in East Texas for approximately
$8.2 million. During the three months ended March 31,
2010, our predecessor participated in the drilling of
3 wells, none of which were dry holes, for a success rate
of 100%.
Financing Activities. Cash flows
provided by financing activities were driven by net advances on
the predecessors revolving credit facility and capital
contributions to fund the development and property acquisition
program.
Predecessor
Working Capital
Our predecessors working capital totaled $4.1 million
and $2.5 million at December 31, 2010 and
March 31, 2011, respectively. Our predecessors
collection of receivables has historically been timely, and
losses associated with uncollectible receivables have
historically not been significant. Our predecessors cash
balances totaled $5.7 million and $2.1 million at
December 31, 2010 and March 31, 2011, respectively.
120
Predecessor
Commodity Derivative Contracts
The following tables summarize, for the periods presented, our
predecessors oil and natural gas swaps, collars and put
options in place as of December 31, 2010. Our predecessor
uses a combination of swaps, collars and put options as a
mechanism for managing commodity price risks. By entering into
these agreements, our predecessor mitigates the effect on its
cash flows of changes in the prices it receives for its oil and
natural gas production. Oil contracts are settled based upon the
NYMEX-WTI price of oil while the natural gas contracts are
settled based upon either the NYMEX-Henry Hub, Tetco-South Texas
or NGPL-TexOk price of natural gas.
|
|
|
|
|
|
|
|
|
Natural Gas Swaps
|
|
|
Weighted Average
|
|
|
Year
|
|
($/MMBtu)
|
|
MMBtu/d
|
|
2011
|
|
$
|
5.698
|
|
|
|
3,633
|
|
2012
|
|
$
|
5.794
|
|
|
|
3,049
|
|
2013
|
|
$
|
5.767
|
|
|
|
2,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Collars
|
|
|
Weighted Average Floor
|
|
Weighted Average Ceiling
|
|
|
Year
|
|
($/MMBtu)
|
|
($/MMBtu)
|
|
MMBtu/d
|
|
2011
|
|
$
|
5.305
|
|
|
$
|
6.761
|
|
|
|
6,542
|
|
2012
|
|
$
|
4.897
|
|
|
$
|
6.177
|
|
|
|
9,016
|
|
2013
|
|
$
|
4.778
|
|
|
$
|
5.790
|
|
|
|
11,474
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Put Options
|
Year
|
|
Floor Price ($/MMBtu)
|
|
MMBtu/d
|
|
2011
|
|
$
|
4.300
|
|
|
|
8,219
|
|
2012
|
|
$
|
4.800
|
|
|
|
2,295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Collars
|
|
|
Weighted Average Floor
|
|
Weighted Average Ceiling
|
|
|
Year
|
|
($/MMBtu)
|
|
($/MMBtu)
|
|
Bbl/d
|
|
2011
|
|
$
|
75.00
|
|
|
$
|
94.00
|
|
|
|
39
|
|
2012
|
|
$
|
73.33
|
|
|
$
|
94.97
|
|
|
|
30
|
|
2013
|
|
$
|
72.00
|
|
|
$
|
103.68
|
|
|
|
25
|
|
Predecessor
Credit Facilities
Our predecessor consists of the combined financial data of
BlueStone Natural Resources Holdings, LLC, or BlueStone, and
certain oil and natural gas properties owned by Classic
Hydrocarbons Holdings, L.P., or Classic.
BlueStone. BlueStone is party to a
$150.0 million revolving credit facility entered into in
June 2010. Amounts outstanding under BlueStones credit
facility are payable on June 25, 2014 with mandatory
pre-payments
required if BlueStone makes any property dispositions.
BlueStones credit facility is secured by mortgages on
substantially all of its properties, including the properties
being contributed to us. We expect that BlueStones credit
facility will be repaid in full with a portion of the cash being
received by Memorial Resource in connection with the closing of
this offering, which repayment will permit the release of the
mortgages on all of the properties being contributed to us.
Amounts outstanding under BlueStones credit facility are
limited to a borrowing base which is determined twice per year.
BlueStone and the administrative agent under the credit facility
can request special borrowing base determinations from time to
time. The borrowing base under BlueStones credit facility
was $90.0 million at March 31, 2011 and the borrowing
base availability was $9.4 million at March 31, 2011.
121
Adjusted Base Rate Advances and Adjusted LIBOR Rate Advances
under BlueStones credit facility bear interest, payable
monthly, at an Adjusted Base Rate or Adjusted LIBOR Rate plus an
applicable margin of 1.75% and 2.75%, respectively, based on the
utilization of the credit facility.
As of March 31, 2011, the interest rate on BlueStones
credit facility, taking into account BlueStones interest
rate swaps, was 3.24%. BlueStones borrowings under its
credit facility totaled $80.3 million at March 31,
2011.
BlueStones credit facility contains financial and other
covenants, including a current ratio test and an interest
coverage test. BlueStone was in compliance with all covenants
under its credit facility at March 31, 2011.
Classic. Classic is party to a
$150.0 million revolving credit facility originally entered
into in November 2007 and amended in June 2010. The credit
facility terminates June 21, 2014. Classics credit
facility is secured by mortgages on substantially all of its
properties, including the properties being contributed to us. We
expect that Classics credit facility will be partially
repaid with a portion of the cash being received by Memorial
Resource in connection with the closing of this offering, which
repayment will permit the release of the mortgages on all of the
properties being contributed to us.
The borrowings under Classics credit facility are secured
by the oil and natural gas properties of Classic and are subject
to semiannual borrowing base redeterminations. The borrowing
base at March 31, 2011 was $115.0 million. Borrowings
under the Classic credit facility bear interest, at the option
of Classic, at either the Prime Rate or LIBOR based rate, in
each case plus an applicable margin determined by the percentage
of the borrowing base outstanding.
As of March 31, 2011, the weighted average interest rate on
Classics credit facility, taking into account
Classics interest rate swaps, was 3.46%. Classics
borrowings under its credit facility totaled $102.0 million
at March 31, 2011.
Classics credit facility contains financial and other
covenants, including a current ratio test and an interest
coverage test. Classic was in compliance with all covenants
under its credit facility at March 31, 2011.
Predecessor
Contractual Obligations
A summary of our predecessors contractual obligations as
of December 31, 2010 is provided in the following table (in
thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
Less Than
|
|
|
|
|
|
|
|
|
More Than
|
|
Contractual Obligation
|
|
Total
|
|
|
One Year
|
|
|
2-3 Years
|
|
|
4-5 Years
|
|
|
5 Years
|
|
|
Revolving credit facility
|
|
$
|
115,222
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
115,222
|
|
|
$
|
|
|
Operating lease
|
|
|
938
|
|
|
|
297
|
|
|
|
418
|
|
|
|
223
|
|
|
|
|
|
Capital lease
|
|
|
59
|
|
|
|
29
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
Other borrowings
|
|
|
222
|
|
|
|
|
|
|
|
138
|
|
|
|
84
|
|
|
|
|
|
Interest expense on long-term debt
|
|
|
12,364
|
|
|
|
2,718
|
|
|
|
4,823
|
|
|
|
4,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations
|
|
$
|
128,805
|
|
|
$
|
3,044
|
|
|
$
|
5,409
|
|
|
$
|
120,352
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts related to our asset retirement obligations are not
included in the table above given the uncertainty regarding the
actual timing of such expenditures. The total amount of
estimated asset retirement obligations at December 31, 2010
is $10.9 million.
Predecessor
Quantitative and Qualitative Disclosure About Market
Risk
Our predecessor is exposed to market risk, including the effects
of adverse changes in commodity prices and interest rates as
described below.
The primary objective of the following information is to provide
quantitative and qualitative information about our
predecessors potential exposure to market risks. The term
market risk refers to the risk of loss
122
arising from adverse changes in oil and natural gas prices and
interest rates. The disclosures are not meant to be precise
indicators of expected future losses, but rather indicators of
reasonably possible losses. All of our predecessors market
risk sensitive instruments were entered into for purposes other
than speculative trading.
Commodity
Price Risk
Our predecessors major market risk exposure is in the
pricing that it receives for its oil and natural gas production.
Realized pricing is primarily driven by the spot market prices
applicable to its natural gas production and the prevailing
price for oil. Pricing for oil and natural gas has been volatile
and unpredictable for several years, and this volatility is
expected to continue in the future. The prices our predecessor
receives for its oil and natural gas production depend on many
factors outside of its control, such as the strength of the
global economy.
To reduce the impact of fluctuations in oil and natural gas
prices on our predecessors revenues, or to protect the
economics of property acquisitions, our predecessor periodically
enters into derivative contracts with respect to a portion of
its projected oil and natural gas production through various
transactions that fix the future prices received. These
transactions may include price swaps whereby our predecessor
will receive a fixed price for its production and pay a variable
market price to the contract counterparty. Additionally, our
predecessor may enter into collars, whereby our predecessor
receives the excess, if any, of the fixed floor over the
floating rate or pays the excess, if any, of the floating rate
over the fixed ceiling price. These hedging activities are
intended to support oil and natural gas prices at targeted
levels and to manage our predecessors exposure to oil and
natural gas price fluctuations. Our predecessor does not enter
into derivative contracts for speculative trading purposes.
Swaps. In a typical commodity swap
agreement, our predecessor receives the difference between a
fixed price per unit of production and a price based on an
agreed upon published third-party index, if the index price is
lower than the fixed price. If the index price is higher, our
predecessor pays the difference. By entering into swap
agreements, our predecessor effectively fixes the price that it
will receive in the future for the hedged production. Our
predecessors swaps are settled in cash on a monthly basis.
For a summary of the oil and natural gas swaps and oil and
natural gas swap prices, related basis swap prices and resulting
adjusted swap prices in place as of March 31, 2011, please
read Predecessor Liquidity and Capital
Resources Predecessor Commodity Derivative
Contracts.
Put Options. In a typical put option
arrangement, our predecessor receives the excess, if any, of the
contract floor price over the reference price, based on NYMEX
quoted prices. Our predecessors current put options are
exercised in cash on a monthly basis only when the floor price
exceeds the reference price, otherwise they expire unsettled.
Collars. In a typical collar
arrangement, our predecessor receives the excess, if any, of the
contract floor price over the reference price, based on NYMEX
quoted prices, and pay the excess, if any, of the reference
price over the contract ceiling price. Our predecessors
current collars are exercised in cash on a monthly basis only
when the reference price is outside of floor and ceiling prices
(the collar), otherwise they expire.
For a summary of the oil and natural gas collars in place as of
March 31, 2011, please read
Predecessor Liquidity and Capital
Resources Predecessor Commodity Derivative
Contracts.
Interest
Rate Risk
At March 31, 2011, our predecessor had an aggregate
$112.6 million of debt outstanding under its credit
facilities, with a weighted average floating interest rate of
3.16%. Assuming no change in the amount outstanding, the impact
on interest expense of a 10% increase or decrease in the average
interest rate, after giving effect to our predecessors
existing interest rate swaps, would be approximately
$0.4 million per year.
123
Counterparty
and Customer Credit Risk
Joint interest receivables arise from entities which own partial
interests in the wells our predecessor operates. These entities
participate in our predecessors wells primarily based on
their ownership in leases on which our predecessor drills. Our
predecessor has limited ability to control participation in its
wells. Our predecessor is also subject to credit risk due to the
concentration of its oil and natural gas receivables with
several significant customers. Please read Business and
Properties Operations Marketing and
Major Customers for further detail about our
predecessors significant customers. The inability or
failure of our predecessors significant customers to meet
their obligations to our predecessor or their insolvency or
liquidation may adversely affect our predecessors
financial results. In addition, our predecessors oil and
natural gas derivative contracts expose our predecessor to
credit risk in the event of nonperformance by counterparties.
While our predecessor does not require its customers to post
collateral and does not have a formal process in place to
evaluate and assess the credit standing of its significant
customers or the counterparties on its derivative contracts, our
predecessor does evaluate the credit standing of its customers
and such counterparties as it deems appropriate under the
circumstances. This evaluation may include reviewing a
counterpartys credit rating and latest financial
information or, in the case of a customer with which our
predecessor has receivables, reviewing their historical payment
record, the financial ability of the customers parent
company to make payment if the customer cannot and undertaking
the due diligence necessary to determine credit terms and credit
limits. The counterparties on our predecessors derivative
contracts currently in place are lenders under BlueStones
and Classics credit facilities, with investment grade
ratings and our predecessor is likely to enter into any future
derivative contracts with these or other lenders under
BlueStones and Classics credit facilities that also
carry investment grade ratings. Several of our
predecessors significant customers for oil and natural gas
receivables have a credit rating below investment grade or do
not have rated debt securities. In these circumstances, our
predecessor has considered the lack of investment grade credit
rating in addition to the other factors described above.
Critical
Accounting Policies and Estimates
Oil
and Natural Gas Properties
We and our predecessor use the successful efforts method of
accounting to account for our and our predecessors oil and
natural gas properties. Under this method, costs of acquiring
properties, costs of drilling successful exploration wells, and
development costs are capitalized. The costs of exploratory
wells are initially capitalized pending a determination of
whether proved reserves have been found. At the completion of
drilling activities, the costs of exploratory wells remain
capitalized if determination is made that proved reserves have
been found. If no proved reserves have been found, the costs of
each of the related exploratory wells are charged to expense. In
some cases, a determination of proved reserves cannot be made at
the completion of drilling, requiring additional testing and
evaluation of the wells. Our and our predecessors policy
is to expense the costs of such exploratory wells if a
determination of proved reserves has not been made within a
twelve-month period after drilling is complete. Exploration
costs such as geological, geophysical, and seismic costs are
expensed as incurred.
As exploration and development work progresses and the reserves
on these properties are proven, capitalized costs attributed to
the properties are subject to depreciation and depletion.
Depletion of capitalized costs is provided using the
units-of-production
method based on proved oil and natural gas reserves related to
the associated field. The timing of any write downs of unproven
properties, if warranted, depends upon the nature, timing, and
extent of planned exploration and development activities and
their results.
On the sale or retirement of a complete or partial unit of a
proved property or pipeline and related facilities, the cost and
related accumulated depreciation, depletion, and amortization
are eliminated from the property accounts, and any gain or loss
is recognized.
124
Oil
and Natural Gas Reserves
The estimates of proved oil and natural gas reserves utilized in
the preparation of the combined financial statements are
estimated in accordance with the guidelines established by the
SEC and the Financial Accounting Standards Board (FASB), which
require that reserve estimates be prepared under existing
economic and operating conditions using a
12-month
average price with no provision for price and cost escalations
in future years except by contractual arrangements. The
estimates of proved reserve information for all of the
Partnership Properties as of December 31, 2010 included in
this prospectus are based on the following:
(1) approximately 53% of the estimated proved reserve
volumes are based on a reserve report relating to our South
Texas properties prepared by the independent petroleum engineers
of NSAI; (2) approximately 35% of the estimated proved
reserve volumes are based on evaluations relating to certain of
our East Texas properties prepared by Memorial Resources
internal reserve engineers and audited by NSAI; and (3) the
remaining approximately 12% of the estimated proved reserve
volumes are based on a reserve report relating to certain of our
East Texas properties prepared by the independent petroleum
engineers of Miller and Lents. Our predecessors annual
reserve estimates were prepared by a third-party petroleum
engineer.
Reserve estimates are inherently imprecise. Accordingly, the
estimates are expected to change as more current information
becomes available. We and our predecessor deplete oil and
natural gas properties by field using the
units-of-production
method. Capitalized drilling and development costs of producing
oil and natural gas properties are depleted over proved
developed reserves and leasehold costs are depleted over total
proved reserves. It is possible that, because of changes in
market conditions or the inherent imprecision of reserve
estimates, the estimates of future cash inflows, future gross
revenues, the amount of oil and natural gas reserves, the
remaining estimated lives of oil and natural gas properties, or
any combination of the above may be increased or reduced.
Increases in recoverable economic volumes generally reduce per
unit depletion rates while decreases in recoverable economic
volumes generally increase per unit depletion rates.
In January 2010, the FASB issued an update to the Oil and Gas
Topic, which aligns the oil and natural gas reserve estimation
and disclosure requirements with the requirements in the
SECs final rule, Modernization of Oil and Gas Reporting
Requirements (the Final Rule). The Final Rule was issued on
December 31, 2008. The Final Rule is intended to provide
investors with a more meaningful and comprehensive understanding
of oil and natural gas reserves, which should help investors
evaluate the relative value of oil and natural gas companies.
The Final Rule permits the use of new technologies to determine
proved reserves estimates if those technologies have been
demonstrated empirically to lead to reliable conclusions about
reserve volume estimates. The Final Rule will also allow, but
not require, companies to disclose their probable and possible
reserves to investors. In addition, the new disclosure
requirements require companies to: (i) report the
independence and qualifications of its reserves preparer or
auditor; (ii) file reports when a third party is relied
upon to prepare reserves estimates or conduct a reserves audit;
and (iii) report oil and natural gas reserves using an
average price based upon the prior
12-month
period rather than a year-end price. The Final Rule became
effective for fiscal years ending on or after December 31,
2009. Our predecessors 2009 and 2010 depletion
calculations were based upon proved reserves that were
determined using the new reserve rules; whereas, the depletion
calculation in 2008 was based on the prior SEC methodology.
Impairments
Proved oil and natural gas properties are reviewed for
impairment when events and circumstances indicate a possible
decline in the recoverability of the carrying value of such
properties, such as a downward revision of the reserve
estimates, less than expected production, drilling results, or
lower commodity prices. The estimated future cash flows expected
in connection with the property are compared to the carrying
value of the property to determine if the carrying amount is
recoverable. If the carrying value of the property exceeds its
estimated undiscounted future cash flows, the carrying amount of
the property is reduced to its estimated fair value. The factors
used to determine fair value include, but are not limited to,
estimates of proved reserves, future commodity prices, the
timing of future production and capital expenditures and a
125
discount rate commensurate with the risk reflective of the lives
remaining for the respective oil and natural gas properties. Our
predecessor accounts for impairment as a Level 3 fair value
computation.
Nonproducing oil and natural gas properties, which consist of
undeveloped leasehold costs and costs associated with the
purchase of proved undeveloped reserves, are assessed for
impairment on a
property-by-property
basis. If the assessment indicates an impairment, a loss is
recognized by providing a valuation allowance. The impairment
assessment is affected by economic factors such as the results
of exploration activities, commodity price outlooks, remaining
lease terms, and potential shifts in business strategy employed
by management.
Asset
Retirement Obligations
We and our predecessor account for obligations associated with
the retirement of tangible long-lived assets and the associated
asset retirement costs. The fair value of a liability for an
asset retirement obligation is recognized in the period in which
it is incurred if a reasonable estimate of fair value can be
made and the associated asset retirement costs are part of the
carrying amount of the long-lived asset.
Revenue
Recognition
Oil and natural gas revenues are recorded using the sales
method. Under this method, we and our predecessor recognize
revenues based on actual volumes of oil and natural gas sold to
purchasers. We, our predecessor and other joint interest owners
may sell more or less than their entitlement share of volumes
produced. A liability is recorded and revenue is deferred if our
predecessors excess sales of natural gas volumes exceed
its estimated remaining recoverable reserves. Our predecessor
had no significant natural gas imbalances at December 31,
2010 or 2009.
Derivative
Instruments
Our predecessor uses derivative financial instruments (swaps,
floors, collars, and forward sales) to reduce the impact of
natural gas and oil price fluctuations and uses interest rate
swaps to manage exposure to interest rate volatility. Every
derivative instrument (including certain derivative instruments
embedded in other contracts) is recorded in the balance sheet as
either an asset or liability measured at its fair value. Changes
in the derivatives fair value are recognized currently in
earnings unless specific hedge accounting criteria are met.
Special accounting for qualifying hedges allows a
derivatives gains and losses to offset related results on
the hedged item in the statements of operations. Companies must
formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting treatment. Our
predecessor had no derivatives designated as hedges at
December 31, 2010 or 2009.
Changes in the fair value of derivative financial instruments
that do not qualify for accounting treatment as hedges are
recognized currently in the statements of operations.
Recently
Issued Accounting Pronouncements
On July 21, 2010, the FASB issued ASU
2010-20
Receivables (Topic 310) Disclosures about the
Credit Quality of Financial Receivables and the Allowance for
Credit Losses. ASU
2010-20
requires disclosure of additional information to assist
financial statement users to understand more clearly an
entitys credit risk exposures to finance receivables and
the related allowance for credit losses. ASU
2010-20 is
effective for all public companies for interim and annual
reporting periods ending on or after December 15, 2010,
with specific items, such as the allowance rollforward and
modification disclosures, effective for periods beginning after
December 15, 2010. We do not expect the adoption of this
new guidance to have an impact on our financial position, cash
flows or results of operations.
In April 2010, the FASB issued ASU
2010-14,
which amends the guidance on oil and natural gas reporting in
Accounting Standards Codification 932.10.S99-1 by adding the
Codification of SEC
Regulation S-X,
Rule 4-10
as amended by the SEC Final
Rule 33-8995.
Both ASU
2010-03 and
ASU 2010-14
are effective for annual reporting periods ending on or after
December 31, 2009. Application of the revised
126
rules is prospective and companies are not required to change
prior period presentation to conform to the amendments.
In January 2010, the FASB issued ASU
2010-06,
Improving Disclosures About Fair Value Measurements,
which provides amendments to fair value disclosures. ASU
2010-06
requires additional disclosures and clarifications of existing
disclosures for recurring and nonrecurring fair value
measurements. The revised guidance for transfers into and out of
Level 1 and Level 2 categories, as well as increased
disclosures around inputs to fair value measurement, was adopted
January 1, 2010, with the amendments to Level 3
disclosures effective beginning after January 1, 2011. ASU
2010-06
concerns disclosure only. Both the current and future adoption
does not have a material impact on our or our predecessors
financial position or results of operations.
Internal
Controls and Procedures
Prior to the completion of this offering, our predecessor has
been a private entity with limited accounting personnel and
other supervisory resources to adequately execute its accounting
processes and address its internal control over financial
reporting. In connection with our predecessors audit for
the year ended December 31, 2010, our predecessors
independent registered accounting firm identified and
communicated material weaknesses related to lack of accounting
personnel with sufficient technical accounting experience for
certain significant or unusual transactions and lack of
management review at the appropriate level for certain
non-routine areas. A material weakness is a
deficiency, or combination of deficiencies, in internal controls
such that there is a reasonable possibility that a material
misstatement of our predecessors financial statements will
not be prevented, or detected in a timely basis. The lack of
technical accounting experience and management review resulted
in several audit adjustments to the financial statements for the
year ended December 31, 2010, 2009, and 2008.
The material weaknesses noted above occurred prior to the
formation of Memorial Resource. Since its formation, Memorial
Resource believes that it has hired appropriate finance and
accounting staff and brought in additional technical and
accounting resources as part of its plan to implement and ensure
the effectiveness of internal controls over financial reporting.
After the closing of this offering, our management team and
financial reporting oversight personnel will be those of
Memorial Resource and our predecessor, and thus, we may face the
same material weaknesses described above.
Prior to the completion of our predecessors audit for the
year ended December 31, 2010, Memorial Resource and our
predecessors management began to implement new accounting
processes and control procedures and also hired additional
personnel.
While we have begun the process of evaluating the design and
operation of our internal control over financial reporting, we
are in the early phases of our review and will not complete our
review until after this offering is completed. We cannot predict
the outcome of our review at this time. During the course of the
review, we may identify additional control deficiencies, which
could give rise to significant deficiencies and other material
weaknesses, in addition to the material weaknesses described
above. Each of the material weaknesses described above could
result in a misstatement of our accounts or disclosures that
would result in a material misstatement of our annual or interim
combined financial statements that would not be prevented or
detected. We cannot assure you that the measures we have taken
to date, or any measures we may take in the future, will be
sufficient to remediate the material weaknesses described above
or avoid potential future material weaknesses.
We are not currently required to comply with the SECs
rules implementing Section 404 of the Sarbanes-Oxley Act of
2002, and are therefore not required to make a formal assessment
of the effectiveness of our internal control over financial
reporting for that purpose. Upon becoming a publicly traded
partnership, we will be required to comply with the SECs
rules implementing Sections 302 and 404 of the
Sarbanes-Oxley Act of 2002, which will require our management to
certify financial and other information in our quarterly and
annual reports and provide an annual management report on the
effectiveness of our internal controls over
127
financial reporting. Though we will be required to disclose
changes made to our internal controls and procedures on a
quarterly basis, we will not be required to make our first
annual assessment of our internal controls over financial
reporting pursuant to Section 404 until the year following
our first annual report required to be filed with the SEC. To
comply with the requirements of being a publicly traded
partnership, we will need to implement additional internal
controls, reporting systems and procedures and hire additional
accounting, finance and legal staff.
Further, our independent registered public accounting firm is
not yet required to formally attest to the effectiveness of our
internal controls over financial reporting until the year
following our first annual report required to be filed with the
SEC. If it is required to do so, our independent registered
public accounting firm may issue a report that is adverse in the
event it is not satisfied with the level at which our controls
are documented, designed or operating. Our remediation efforts
may not enable us to remedy or avoid material weaknesses or
significant deficiencies in the future.
Inflation
Inflation in the United States has been relatively low in recent
years and did not have a material impact on our
predecessors results of operations for the years ended
December 31, 2008, 2009 and 2010. Although the impact of
inflation has been insignificant in recent years, it is still a
factor in the U.S. economy, and we expect to experience
inflationary pressure on the cost of oilfield services and
equipment when increasing oil and natural gas prices increase
drilling activity in our areas of operations.
Off-Balance
Sheet Arrangements
Currently, neither we nor our predecessor have any off-balance
sheet arrangements.
128
BUSINESS
AND PROPERTIES
The following Business and Properties discussion should be
read in conjunction with the Selected Historical and Pro
Forma Financial Data and the accompanying financial
statements and related notes included elsewhere in this
prospectus. Unless otherwise indicated, all references to
financial or operating data on a pro forma basis give effect to
the transactions described under Summary Our
Partnership Structure and Formation Transactions and in
the Unaudited Pro Forma Combined Financial Statements included
elsewhere in this prospectus.
Our pro forma estimated proved reserve information for all of
the Partnership Properties as of December 31, 2010 is based
on the following: (1) approximately 53% of the estimated
proved reserve volumes are based on a reserve report relating to
our South Texas properties prepared by the independent petroleum
engineers of NSAI; (2) approximately 35% of the estimated
proved reserve volumes are based on evaluations relating to
certain of our East Texas properties prepared by Memorial
Resources internal reserve engineers and audited by NSAI;
and (3) the remaining approximately 12% of the estimated
proved reserve volumes are based on a reserve report relating to
certain of our East Texas properties prepared by the independent
petroleum engineers of Miller and Lents. We refer to these
evaluations and reports collectively as our reserve
reports.
Overview
We are a Delaware limited partnership formed in April 2011 by
Memorial Resource to own and acquire oil and natural gas
properties in North America. Our primary business objective is
to generate stable cash flows, allowing us to make quarterly
cash distributions to our unitholders and, over time, to
increase those quarterly cash distributions. We believe our
properties are well suited for our partnership because they
consist of mature onshore oil and natural gas reservoirs with
long-lived, predictable production profiles and modest capital
requirements. As of December 31, 2010, our total estimated
proved reserves were approximately 325 Bcfe, of which
approximately 81% were classified as proved developed reserves.
Based on our pro forma average net production for the year ended
December 31, 2010 of 52 MMcfe/d, our total estimated
proved reserves had a
reserve-to-production
ratio of 17 years. Based on proved reserves volumes at
December 31, 2010, we or Memorial Resource operate 94% of
the properties in which we have interests, and we own an average
working interest of 41% across our oil and natural gas
properties.
We believe our business relationship with Memorial Resource,
which owns our general partner and will own approximately % of
our outstanding common units and all of our subordinated units,
will enhance our ability to maintain or grow our production and
expand our proved reserves base over time. Memorial Resource is
a Delaware limited liability company formed by Natural Gas
Partners VIII, L.P. and Natural Gas Partners IX, L.P., which we
refer to as the Funds, to own, acquire, exploit and develop oil
and natural gas properties and to own our general partner. As
part of the formation transactions, the Funds will contribute to
Memorial Resource their respective ownership of five separate
portfolio companies (including our predecessor), all of which
are engaged in the business of owning, acquiring, exploiting,
and developing oil and natural gas properties, and certain of
which will contribute the Partnership Properties to us. Memorial
Resource will engage in its business with the objective of
growing its reserves, production and cash flows, as well as
owning our general partner and a significant limited partner
interest in us.
Our
Properties
Our properties are located in South and East Texas and consist
of mature, legacy onshore oil and natural gas reservoirs. We
believe our properties are well suited for our partnership
because they have predictable production profiles, low decline
rates, long reserve lives and modest capital requirements. The
Partnership Properties consist of operated working interests in
producing and undeveloped leasehold acreage and in identified
producing wells in South and East Texas, and non-operated
working interests in producing and undeveloped leasehold
acreage. As of December 31, 2010, we owned
133,309 gross (112,828 net) acres of developed
properties and 11,876 gross (4,501 net) acres of
undeveloped properties, all held by production, with 345 proved
low-risk infill drilling, recompletion and development
opportunities in our core operational areas. As of
December 31, 2010, we had interests in 1,290 gross
(609 net) producing wells across our
129
properties, with an average working interest of 47%. Based on
our reserve reports, the average estimated decline rate for our
existing proved developed producing reserves is approximately 9%
for 2011, approximately 9% compounded average decline for the
subsequent four years and approximately 8% thereafter. As of
December 31, 2010, approximately 60 Bcfe, or 19%, of
our estimated proved reserves were classified as proved
undeveloped, of which approximately 83% were natural gas. Based
on the production estimates and pricing assumptions included in
our reserve reports, we believe that through 2015, our low-risk
development inventory will provide us with the opportunity to
maintain our targeted average net production of 49 MMcfe/d
without acquiring incremental reserves.
The following table summarizes pro forma information by
producing region regarding our estimated oil and natural gas
reserves as of December 31, 2010 and our average net
production for the year ended December 31, 2010. The
reserve estimates attributable to the Partnership Properties are
derived from our reserve reports.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Pro Forma
|
|
|
Average Net
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Net Proved Reserves
|
|
|
Pro Forma
|
|
|
Reserve-to-
|
|
|
Producing
|
|
|
|
|
|
|
% Natural
|
|
|
% Proved
|
|
|
Production
|
|
|
Production
|
|
|
Wells
|
|
|
|
Bcfe
|
|
|
Gas
|
|
|
Developed
|
|
|
MMcfe/d
|
|
|
%
|
|
|
Ratio(1)
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Years)
|
|
|
|
|
|
|
|
|
South Texas
|
|
|
172.2
|
|
|
|
98
|
%
|
|
|
87
|
%
|
|
|
32
|
|
|
|
61
|
%
|
|
|
15
|
|
|
|
563
|
|
|
|
424
|
|
East Texas
|
|
|
152.5
|
|
|
|
76
|
%
|
|
|
76
|
%
|
|
|
20
|
|
|
|
39
|
%
|
|
|
21
|
|
|
|
727
|
|
|
|
185
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
324.7
|
|
|
|
88
|
%
|
|
|
81
|
%
|
|
|
52
|
|
|
|
100
|
%
|
|
|
17
|
|
|
|
1,290
|
|
|
|
609
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The average
reserve-to-production
ratio is calculated by dividing estimated pro forma net proved
reserves as of December 31, 2010 by average pro forma net
production for the year ended December 31, 2010. |
Our
Hedging Strategy
We expect to adopt a hedging policy designed to reduce the
impact to our cash flows from commodity price volatility. Under
this policy, we intend to enter into commodity derivative
contracts covering approximately 65% to 85% of our estimated
production from total proved developed producing reserves over a
three-to-five
year period at any given point of time. We may, however, from
time to time hedge more or less than this approximate range.
Memorial Resource will contribute to us at the closing of this
offering derivative contracts for the six months ending
December 31, 2011 and the years ending December 31,
2012, 2013, 2014, and 2015 covering approximately 76%, 75%, 69%,
14% and 8%, respectively, of our estimated production from our
total proved developed producing reserves existing as of
December 31, 2010, based on our reserve reports.
Our commodity derivative contracts may consist of natural gas,
oil and NGL financial swaps, put options
and/or
collar contracts and natural gas basis financial swaps. By
removing a significant portion of price volatility associated
with production, we believe we will mitigate, but not eliminate,
the potential negative effects of reductions in commodity prices
on our cash flow from operations for those periods. However, our
hedging activity may also reduce our ability to benefit from
increases in commodity prices. Additionally, we intend to
individually identify these
non-speculative
hedges as designated hedges for U.S. federal
income tax purposes as we enter into them. For a description of
our commodity derivative contracts, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Pro Forma
Liquidity and Capital Resources Commodity Derivative
Contracts.
Our
Principal Business Relationships
We view our relationships with Memorial Resource, Natural Gas
Partners and the Funds as significant competitive strengths. We
believe these relationships will provide us with potential
acquisition opportunities from a portfolio of additional oil and
natural gas properties that meet our acquisition criteria, as
well as access to personnel with extensive technical expertise
and industry relationships.
130
Our
Relationship with Memorial Resource
Following the completion of this offering, Memorial Resource
will be our largest unitholder,
holding
common units (approximately % of
all outstanding)
and
subordinated units (100% of all outstanding), and will own the
voting interests in our general partner and 50% of the economic
interest in our incentive distribution rights. After giving
effect to the formation transactions, Memorial Resource had
(i) total estimated proved reserves of 1,036 Bcfe at
December 31, 2010, primarily located in East Texas, North
Louisiana and the Rockies, of which approximately 81% were
natural gas, and approximately 34% were classified as proved
developed reserves, and (ii) interests in over
398,000 gross (173,000 net) acres of undeveloped
properties. We believe that many of these properties are (or
after additional capital is invested will become) suitable for
us, based on our criteria that suitable properties consist of
mature onshore oil and natural gas reservoirs with long-lived,
low-decline, predictable production profiles. We also believe
the largely contiguous and overlapping nature of Memorial
Resources and our East Texas acreage, along with joint
ownership in specific properties, will provide key operational,
logistical and technical benefits derived from our aligned
interests and information sharing among personnel, in addition
to various economic benefits.
The following table summarizes pro forma information by
producing region regarding Memorial Resources estimated
oil and natural gas reserves as of December 31, 2010 and
its average net production for the year ended December 31,
2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated Pro Forma
|
|
|
Average Net
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Net Proved Reserves(1)
|
|
|
Pro Forma
|
|
|
Reserve-to-
|
|
|
|
|
|
|
|
|
|
|
|
|
% Natural
|
|
|
% Proved
|
|
|
Production
|
|
|
Production
|
|
|
Producing Wells
|
|
|
|
Bcfe
|
|
|
Gas
|
|
|
Developed
|
|
|
MMcfe/d
|
|
|
%
|
|
|
Ratio(2)
|
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Years)
|
|
|
|
|
|
|
|
|
East Texas(3)
|
|
|
760.6
|
|
|
|
84
|
%
|
|
|
30
|
%
|
|
|
43
|
|
|
|
64
|
%
|
|
|
48
|
|
|
|
1,067
|
|
|
|
306
|
|
North Louisiana
|
|
|
224.7
|
|
|
|
73
|
%
|
|
|
44
|
%
|
|
|
18
|
|
|
|
27
|
%
|
|
|
35
|
|
|
|
267
|
|
|
|
172
|
|
Rockies
|
|
|
51.0
|
|
|
|
67
|
%
|
|
|
41
|
%
|
|
|
6
|
|
|
|
9
|
%
|
|
|
25
|
|
|
|
123
|
|
|
|
85
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,036.3
|
|
|
|
81
|
%
|
|
|
34
|
%
|
|
|
67
|
|
|
|
100
|
%
|
|
|
43
|
|
|
|
1,457
|
|
|
|
563
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Memorial Resources estimated pro forma net proved reserves
are based primarily on reserve reports prepared by third-party
independent petroleum engineers. |
|
(2) |
|
The average
reserve-to-production
ratio is calculated by dividing estimated pro forma net proved
reserves as of December 31, 2010 by average pro forma net
production for the year ended December 31, 2010. |
|
(3) |
|
Includes 169 Bcfe of reserves associated with properties in
which we have a joint ownership interest. Please read
Summary Our Partnership Structure and
Formation Transactions Background Information
Regarding Our Predecessor and the Partnership Properties. |
As a result of its significant ownership interests in us and our
general partner, we believe Memorial Resource will be motivated
to support the successful execution of our business strategy and
will provide us with opportunities to pursue acquisitions that
will be accretive to our unitholders. Memorial Resource views
our partnership as part of its growth strategy, and we believe
that Memorial Resource will be incentivized to contribute or
sell additional assets to us and to pursue acquisitions jointly
with us in the future. However, Memorial Resource will regularly
evaluate acquisitions and dispositions and may elect to acquire
or dispose of properties in the future without offering us the
opportunity to participate in those transactions. Moreover,
after this offering, Memorial Resource will continue to be free
to act in a manner that is beneficial to its interests without
regard to ours, which may include electing not to present us
with future acquisition opportunities. Although we believe
Memorial Resource will be incentivized to offer properties to us
for purchase, none of Memorial Resource, the Funds or any of
their affiliates will have any obligation to sell or offer
properties to us following the consummation of this offering. If
Memorial Resource fails to present us with, or successfully
competes against us for, acquisition opportunities, then our
ability to replace or increase our estimated proved reserves may
be impaired, which would adversely affect our cash flow from
operations and our ability to make cash distributions to our
unitholders. Please read Conflicts of Interest and
Fiduciary Duties.
131
Memorial Resource will also provide management, administrative,
and operations personnel to us and our general partner under an
omnibus agreement that it will enter into with us and our
general partner at the completion of this offering. Under this
agreement, we will utilize Memorial Resources staff of 50
engineers and geologists and 54 management and administrative
personnel as of May 31, 2011, who collectively have an
average of 24 years of experience operating properties in
our areas of operations. Please read Management for
more information about the management of our partnership and our
use of Memorial Resource personnel, and Certain
Relationships and Related Party Transactions
Agreements Governing the Transactions Omnibus
Agreement for more information about the omnibus agreement.
Our
Relationship with NGP and the Funds
Founded in 1988, NGP is a family of private equity investment
funds with aggregate committed capital of over $7 billion,
organized to make direct equity investments in the energy
industry. NGP is part of the investment platform of NGP Energy
Capital Management, one of the leading investment franchises in
the natural resources sector with over $9 billion in
aggregate committed capital under management. The employees of
NGP are experienced energy professionals with substantial
expertise in investing in the oil and natural gas business. In
connection with NGPs business, these employees review a
large number of potential acquisitions and are involved in
decisions relating to the acquisition and disposition of oil and
natural gas assets by the various portfolio companies in which
NGP owns interests. We believe that our relationship with NGP,
and its experience investing in oil and natural gas companies,
provides us with a number of benefits, including increased
exposure to acquisition opportunities and access to a
significant group of transactional and financial professionals
who have experience in assisting the companies in which it has
invested to meet their financial and strategic growth
objectives. Although we may have the opportunity to make
acquisitions as a result of our relationship with NGP, NGP has
no legal obligation to offer to us (or inform us about) any
acquisition opportunities, may decide not to offer any
acquisition opportunities to us and is not restricted from
competing with us, and we cannot say which, if any, of such
potential acquisition opportunities we would choose to pursue.
The Funds, which are two of the private equity funds managed by
NGP, collectively own 100% of Memorial Resource. The Funds also
will collectively directly own, through non-voting membership
interests in our general partner, 50% of the economic interest
in our incentive distribution rights. The remaining economic
interest in our incentive distribution rights is owned by
Memorial Resource. Given this alignment of interests between
NGP, the Funds, Memorial Resource and us, we believe we will
benefit from the collective expertise of NGPs employees
and their extensive network of industry relationships, and
accordingly the access to potential acquisition opportunities
that might not otherwise be available to us.
Our
Business Strategies
Our primary business objective is to generate stable cash flows,
allowing us to make quarterly cash distributions to our
unitholders and, over time, to increase those quarterly cash
distributions. To achieve our objective, we intend to execute
the following business strategies:
|
|
|
|
|
Maintain and Grow a Stable Production Profile through
Accretive Acquisitions and Low-Risk
Development. Our development plans will
target proved drilling locations that are low cost, present
minimal risk, and support a stable production profile. We will
seek to acquire proved developed properties with long-lived
reserves, low production decline rates and identified and
predictable development potential. We believe that our
management teams experience positions us to identify,
evaluate, execute, integrate and exploit suitable acquisitions.
|
|
|
|
Strategically Utilize Our Relationship with Memorial
Resource, the Funds, and their Respective Affiliates (Including
NGP) to Gain Access to and, from Time to Time, Acquire Producing
Oil and Natural Gas Properties that Meet Our Acquisition
Criteria. We may have the opportunity to
acquire producing oil and natural gas properties directly from
Memorial Resource, the Funds, or their respective affiliates
from time to time in the future. While none of Memorial
Resource, the Funds, or any of their respective affiliates is
contractually obligated to offer or sell any properties to us,
we
|
132
|
|
|
|
|
believe that selling properties to us will enhance Memorial
Resources and, accordingly, the Funds economic
returns by monetizing long-lived producing properties while
potentially retaining a portion of the resulting cash flow
through distributions on Memorial Resources (and the
Funds) limited partner and incentive distribution
interests in us.
|
|
|
|
|
|
Leverage Our Relationships with Memorial Resource, the
Funds, and their Respective Affiliates (Including NGP) to
Participate in Acquisitions of Third Party Producing Properties
and to Increase the Size and Scope of Our Potential Third-Party
Acquisition Targets. Memorial Resource was
formed in part to acquire and develop oil and natural gas
properties, some of which will likely meet our acquisition
criteria. In addition, NGP and its affiliates (including the
Funds) have long histories of pursuing and consummating oil and
natural gas property acquisitions in North America. Through our
relationships with Memorial Resource, the Funds, and their
respective affiliates (including NGP), we expect that we will
have access to their significant pool of management talent and
industry relationships, which we believe will provide us a
competitive advantage in pursuing potential third-party
acquisition opportunities. We may have the opportunity to work
jointly with Memorial Resource to pursue certain acquisitions of
oil and natural gas properties that may not otherwise be
attractive acquisition candidates for any of us individually.
For example, we may jointly pursue an acquisition where we would
acquire the proved developed portion of the acquired properties
and Memorial Resource would acquire the undeveloped portion. We
believe this arrangement will give us access to an array of
third-party acquisition opportunities that we would not
otherwise be in a position to pursue.
|
|
|
|
Exploit Opportunities on Our Current Properties and Manage
Our Operating Costs and Capital
Expenditures. We intend to pursue low-risk
drilling of our proved undeveloped inventory and to perform
cost-reducing operational enhancements. Pursuant to the omnibus
agreement, Memorial Resource will provide us and our general
partner with operating, management, and administrative services,
which we believe will provide us with significant technical
expertise and experience that will allow us to identify and
execute cost-reducing exploitation and operational improvements
on both our existing properties and new acquisitions. Memorial
Resources operational control of substantially all of our
proved reserves as well as its own, often adjoining or
complementary properties, enables direct influence and
implementation of cost reduction initiatives.
|
|
|
|
Reduce Exposure to Commodity Price Risk and Stabilize Cash
Flows Through a Disciplined Commodity Hedging
Policy. We intend to maintain a portfolio of
commodity derivative contracts covering approximately 65% to 85%
of our estimated production from total proved developed
producing reserves over a
three-to-five
year period at any given point in time. These commodity
derivative contracts may consist of natural gas, oil and NGL
financial swaps and collar contracts and natural gas basis
financial swaps. Memorial Resource will contribute to us at the
closing of this offering derivative contracts for the six months
ending December 31, 2011 and the years ending
December 31, 2012, 2013, 2014, and 2015 covering
approximately 76%, 75%, 69%, 14% and 8%, respectively, of our
estimated production from our total proved developed producing
reserves existing as of December 31, 2010, based on our
reserve reports. We believe these commodity derivative contracts
will allow us to mitigate the impact of oil and natural gas
price volatility, thereby increasing the predictability of our
cash flow.
|
|
|
|
Maintain Reasonable Levels of Indebtedness to Permit us to
Opportunistically Finance Acquisitions. We
intend to maintain modest levels of indebtedness in relation to
our cash flows from operations. We believe our internally
generated cash flows and our borrowing capacity under our new
revolving credit facility will provide us with the financial
flexibility to pursue our acquisition and development strategy
in an effective and competitive manner.
|
133
Our
Competitive Strengths
We believe that the following competitive strengths will allow
us to successfully execute our business strategies and achieve
our objective of generating and growing cash available for
distribution:
|
|
|
|
|
Our Long-Lived Reserves with Significant Production
History and Predictable Production Decline
Rates. Our pro forma estimated proved
reserves as of December 31, 2010 divided by our pro forma
average net production for 2010, which we refer to as our
reserve to production index, was 17 years. Based on our
reserve reports, the average estimated decline rate for our
existing proved developed producing reserves is approximately 9%
for 2011, approximately 9% compounded average decline for the
subsequent four years and approximately 8% thereafter. Our
estimated average well life for producing reserves is
12 years, providing a long history of production that
enables better predictability of future production decline rates.
|
|
|
|
Our Relationships with Memorial Resource, the Funds, and
their Respective Affiliates (Including NGP), which we Believe
will Provide us with Access to a Portfolio of Additional Oil and
Natural Gas Properties that Meet Our Acquisition
Criteria. Memorial Resource was formed in
part to own and acquire producing properties and to develop
properties into mature, long-lived producing assets. After
giving effect to the formation transactions, Memorial Resource
had (i) total estimated proved reserves of 1,036 Bcfe
at December 31, 2010, primarily located in East Texas,
North Louisiana and the Rockies, of which approximately 81% were
natural gas, and approximately 34% were classified as proved
developed reserves, and (ii) interests in over
398,000 gross (173,000 net) acres of undeveloped
properties. Based on Memorial Resources intention to
develop its properties and Memorial Resources significant
ownership interests in us, we believe we may be able to acquire
additional assets from Memorial Resource, the Funds, or their
respective affiliates in the future. None of Memorial Resource,
the Funds, or any of their respective affiliates will have any
obligation to offer or sell properties to us following the
consummation of this offering.
|
|
|
|
Our Management Teams Extensive Experience in the
Acquisition, Development and Integration of Oil and Natural Gas
Assets. The members of our management team
and Memorial Resource collectively have an average of
24 years of experience in the oil and natural gas industry.
John A. Weinzierl, the President, Chief Executive Officer and
Chairman of our general partner, has 20 years of oil and
natural gas industry experience, a strong commercial and
technical background and extensive experience acquiring and
managing oil and natural gas properties for NGP.
|
|
|
|
Our Relationship with Memorial Resource, which Provides us
with Extensive Technical Expertise in and Familiarity with
Developing and Operating Oil and Natural Gas Assets within Our
Core Focus Areas. Through the omnibus
agreement with Memorial Resource, we have the operational
support of a staff of 50 petroleum professionals, many of whom
have significant engineering and geoscience expertise in South
and/or East
Texas, which are our current geographical areas of focus. We
believe that this technical expertise differentiates us from,
and provides us with a competitive advantage over, many of our
competitors. We intend to utilize these resources in maximizing
our production and ultimate reserve recovery, which could add
substantial value to our assets.
|
|
|
|
Our Relationships with Memorial Resource, the Funds, and
their Respective Affiliates (Including NGP), which we Believe
will Help us with Access to and in the Evaluation and Execution
of Future Acquisitions. We believe that our
ability to use the industry relationships and broad expertise of
Memorial Resource and NGP in expanding our access to
acquisitions and evaluating oil and natural gas assets will
expand our opportunities and differentiate us from many of our
competitors. Additionally, we expect to have the opportunity to
work jointly with Memorial Resource to pursue acquisitions of
oil and natural gas properties that we would not otherwise be
able to pursue on our own or that may not otherwise be
attractive acquisition candidates for any of us individually.
|
|
|
|
Our Diverse Distribution of Reserve Value, with
1,290 Gross (609 Net) Producing Wells as of
December 31, 2010, None of which Contains Estimated Proved
Reserves in Excess of 2% of Our Total Estimated Proved Reserves
as of December 31, 2010. The value of
our pro forma estimated
|
134
|
|
|
|
|
proved reserves, as approximated by the standardized measure, is
spread across a wide subset of our producing wells. Our top
10 wells by value represent 11% of our total standardized
measure at December 31, 2010. The value of our pro forma
estimated proved reserves, as approximated by the standardized
measure, is also widely distributed across our producing fields.
No producing field in our pro forma estimated proved reserves
represents more than 36% of our standardized measure at
December 31, 2010.
|
|
|
|
|
|
Our Inventory of 345 Proved Low-Risk Infill Drilling,
Recompletion and Development Opportunities in Our Core
Operational Areas. We have a substantial
inventory of low risk, proved undeveloped locations. At
December 31, 2010, the Partnership Properties included
60 Bcfe of estimated proved undeveloped reserves, and had
70 proved identified low-risk proved drilling locations and
275 proved recompletion and development opportunities.
Based on our current asset portfolio, we intend to spend
approximately $9.2 million for capital expenditures for the
twelve months ending June 30, 2012 based on our reserve
reports, which amount spent annually we believe will also enable
us to maintain our targeted average net production from our
assets of 49 MMcfe/d through December 31, 2015.
|
|
|
|
Our Competitive Cost of Capital and Financial
Flexibility. Unlike our corporate
competitors, we do not expect to be subject to federal income
taxation at the entity level. We believe that this attribute
should provide us with a lower cost of capital compared to many
of our competitors, thereby enhancing our ability to compete for
future acquisitions, both individually and jointly with Memorial
Resource. We also expect that our ability to issue additional
common units and other partnership interests in connection with
acquisitions will enhance our financial flexibility. Further, we
intend to utilize a modest amount of debt to provide flexibility
in our capital structure.
|
Properties
At the closing of this offering, we will own mineral interests
and leasehold interests in oil and natural gas producing
properties and certain identified producing wells, as well as in
certain undeveloped properties and acreage, substantially all of
which are located in South Texas and East Texas. The Partnership
Properties consist of mature onshore oil and natural gas
reservoirs with long-lived, predictable production profiles.
Specifically, our properties and wells are located in fields
that generally have been producing for a long period of time,
typically more than 20 years. Observing the performance of
these fields over many years allows for greater understanding of
production and reservoir characteristics, making future
performance more predictable. In other words, the production and
corresponding decline rates attributable to properties of this
type, in contrast with more recently drilled properties, can be
forecasted with a greater degree of accuracy. We use words such
as mature to describe our producing properties as
having established operating, reservoir and production
characteristics. The wells and producing properties included in
the Partnership Properties were chosen primarily because we
expect that the greater precision in forecasted production
attributable to the properties will result in more stable cash
flows.
The development and production of oil and natural gas has a
number of uncertainties that pose substantial risk, even for
mature properties such as our producing properties. However, we
view our producing properties as less risky because many of the
operational risks associated with oil and natural gas production
(for example, drilling a well, whether one will discover
hydrocarbons capable of production in paying quantities, and
initial production decline rate) tend to occur earlier in the
lifecycle of oil and natural gas properties. For a discussion of
the risks inherent in oil and natural gas production, please
read Risk Factors Risks Related to Our
Business Our estimated proved reserves and future
production rates are based on many assumptions that may prove to
be inaccurate. Any material inaccuracies in these reserve
estimates or underlying assumptions will materially affect the
quantities and present value of our estimated reserves.
The following table shows the pro forma estimated net proved oil
and natural gas reserves of the principal fields located in the
Partnership Properties, based on our reserve reports. The
following table also shows certain unaudited information
regarding production and sales of oil and natural gas with
respect to such properties. Our six principal fields detailed
below represent approximately 71% of our total pro forma
estimated net proved reserves as of December 31, 2010 and
73% of our average daily net production for the
135
year ended December 31, 2010. Please read Risk
Factors and Managements Discussion and
Analysis of Financial Condition and Results of Operations
in evaluating the material presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma Average Net Production for the
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2010
|
|
|
Average
|
|
|
|
Estimated Net Proved Reserves
|
|
|
|
|
|
% of
|
|
|
Reserve-to-
|
|
|
|
|
|
|
% Proved
|
|
|
% Natural
|
|
|
% of
|
|
|
|
|
|
Total
|
|
|
Production
|
|
|
|
MMcfe
|
|
|
Developed
|
|
|
Gas
|
|
|
Total
|
|
|
(MMcfe/d)
|
|
|
Production
|
|
|
Ratio
|
|
|
South Texas Fields:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NE Thompsonville
|
|
|
32,312
|
|
|
|
85
|
%
|
|
|
100
|
%
|
|
|
19
|
%
|
|
|
7
|
|
|
|
23
|
%
|
|
|
12
|
|
Laredo
|
|
|
23,993
|
|
|
|
63
|
%
|
|
|
98
|
%
|
|
|
14
|
%
|
|
|
5
|
|
|
|
17
|
%
|
|
|
12
|
|
Hubberd
|
|
|
19,166
|
|
|
|
100
|
%
|
|
|
98
|
%
|
|
|
11
|
%
|
|
|
3
|
|
|
|
9
|
%
|
|
|
18
|
|
East Seven Sisters
|
|
|
17,820
|
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
10
|
%
|
|
|
4
|
|
|
|
12
|
%
|
|
|
13
|
|
Other
|
|
|
78,871
|
|
|
|
88
|
%
|
|
|
97
|
%
|
|
|
46
|
%
|
|
|
12
|
|
|
|
39
|
%
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total South Texas Fields
|
|
|
172,161
|
|
|
|
87
|
%
|
|
|
98
|
%
|
|
|
100
|
%
|
|
|
32
|
|
|
|
100
|
%
|
|
|
15
|
|
East Texas Fields:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carthage
|
|
|
117,721
|
|
|
|
73
|
%
|
|
|
72
|
%
|
|
|
77
|
%
|
|
|
12
|
|
|
|
57
|
%
|
|
|
28
|
|
Joaquin
|
|
|
18,519
|
|
|
|
100
|
%
|
|
|
99
|
%
|
|
|
12
|
%
|
|
|
7
|
|
|
|
35
|
%
|
|
|
7
|
|
Other
|
|
|
16,296
|
|
|
|
100
|
%
|
|
|
81
|
%
|
|
|
11
|
%
|
|
|
2
|
|
|
|
8
|
%
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total East Texas Fields
|
|
|
152,536
|
|
|
|
76
|
%
|
|
|
76
|
%
|
|
|
100
|
%
|
|
|
20
|
|
|
|
100
|
%
|
|
|
21
|
|
All Fields
|
|
|
324,697
|
|
|
|
81
|
%
|
|
|
88
|
%
|
|
|
100
|
%
|
|
|
52
|
|
|
|
100
|
%
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary
of Oil and Natural Gas Properties and Projects
Substantially all of our estimated proved reserves as of
December 31, 2010, and substantially all of our average
daily net production for the year ended December 31, 2010,
were located in South and East Texas. As of December 31,
2010, we had interests in 1,290 gross (609 net) producing
wells across our properties, with an average working interest of
47%, and substantially all of our properties are operated by us
or Memorial Resource. Our wells produce natural gas from various
formations at depths from approximately 6,000 to
15,000 feet. During the calendar years 2011 and 2012, we
plan to drill 7 gross (4 net) wells and perform
various recompletion and workover related activities for an
estimated cost of $16.1 million net to our interest.
Operations on the fields where our properties are located
typically result in long-lived reserves, high drilling success
rates and predictable declines, often resulting in average
reserve-to-production
ratios in excess of 20 years. Once drilled and completed,
producing wells on these fields generally do not require any
material capital expenditures and historically have had minimal
operating and maintenance requirements. Our pro forma estimated
proved reserves as of December 31, 2010 totaled
325 Bcfe. For the year ended December 31, 2010, our
properties produced a net average of 52 MMcfe/d at an
average cash production cost of $1.60 per Mcfe (excluding
general and administrative expenses). Our properties have a
proved developed producing production decline rate of
approximately 8% per year over the next ten years and a
reserve-to-production
ratio of approximately 17 years based on our reserve
reports.
South Texas. Approximately 53% of our
estimated proved reserves as of December 31, 2010 and
approximately 61% of our pro forma average daily net production
for the year ended December 31, 2010 were located in the
South Texas region. Our South Texas properties include wells and
properties in numerous natural gas weighted fields located in
McMullen, Duval, Jim Hogg, Webb and Zapata Counties, Texas,
including West Rhode Ranch, East Seven Sisters and NE
Thompsonville fields. Our properties in these fields contained
172 Bcfe of estimated net proved reserves as of
December 31, 2010 based on our reserve reports. Those
properties collectively generated average net production of
32 MMcfe/d for the year ended December 31, 2010.
136
NE Thompsonville Field. The NE Thompsonville
Field is a natural gas weighted field located in Jim Hogg
County, Texas. The key producing lease in the field is the Mars
McLean Trust. Since its discovery in 1959, the field has
produced approximately 850 Bcfe. Production from the field
is primarily from the Wilcox formation at an average depth
between approximately 9,600 and 14,500 feet. We operate
35 gross (33 net) producing wells in the NE Thompsonville
Field with an average working interest of 93%. As of
December 31, 2010, our properties in the field contained
32 Bcfe of estimated net proved reserves and generated
average net production of 7 MMcfe/d for the year ended
December 31, 2010.
Laredo Field. The Laredo Field is a natural
gas weighted field located in Webb County, Texas. Since its
discovery in 1965, the field has produced approximately
254 Bcfe. Production from the field is primarily from the
Wilcox Lobo Formation at a depth range between 6,500 and
7,500 feet. We operate 97 gross (65 net) producing
wells in the field with an average working interest of 67%. As
of December 31, 2010, our properties in the field contained
24 Bcfe of estimated net proved reserves and generated
average net production of 5 MMcfe/d for the year ended
December 31, 2010.
Hubberd Field. The Hubberd Field is a natural
gas weighted field located in Webb County, Texas. Since its
discovery in 1974, the field has produced approximately
85 Bcfe. Production from the field is primarily from the
Wilcox Lobo Formation at a depth range between 7,000 and
8,000 feet. We operate 51 gross (50 net) producing
wells in the field with an average working interest of 97%. As
of December 31, 2010, our properties in the field contained
19 Bcfe of estimated net proved reserves and generated
average net production of 3 MMcfe/d for the year ended
December 31, 2010.
East Seven Sisters Field. The East Seven
Sisters Field is a natural gas weighted field located in Duval
County, Texas. The key producing lease in the field is Arco
Humble Fee. Since its discovery in 1981, the field has produced
approximately 400 Bcfe. Production from the field is
primarily from the Wilcox formation at an average depth between
approximately 10,000 and 15,000 feet. We operate
12 gross (10 net) producing wells in the East Seven Sisters
Field with an average working interest of 81%. As of
December 31, 2010, our properties in the field contained
18 Bcfe of estimated net proved reserves and generated
average net production of 4 MMcfe/d for the twelve months
ended December 31, 2010.
East Texas. Approximately 47% of our
estimated proved reserves as of December 31, 2010 and
approximately 39% of our pro forma average daily net production
for the year ended December 31, 2010 were located in the
East Texas region. Our East Texas properties include properties
in the Joaquin and Carthage fields, adjacent natural gas
weighted fields located in Panola and Shelby counties, which
collectively contained 153 Bcfe of estimated net proved
reserves as of December 31, 2010 based on our reserve
reports. Those properties collectively generated average net
production of 20 MMcfe/d for the year ended
December 31, 2010. The Joaquin and Carthage fields contain
substantially the same stratigraphic intervals and each contains
multiple production units.
Joaquin Field. This field was discovered in
1936 and has produced approximately 582 Bcfe through
December 31, 2010. Production from the field is primarily
from the Travis Peak and Cotton Valley Formations at an average
depth between approximately 6,000 and 9,000 feet. The
Travis Peak and Cotton Valley Formations consist of multiple
stacked sandstone reservoirs. These reservoirs are developed
with both vertical and horizontal wells and multiple zone
completions. We or Memorial Resource operate 111 gross (96
net) producing wells in the Joaquin Field, with an average
working interest of 87%.
Carthage Field. This field was discovered in
1936 and has produced approximately 13,100 Bcfe through
December 31, 2010. Production from the field is primarily
from the Cotton Valley Formation at an average depth of
approximately 9,000 feet. The Cotton Valley Formation
consists of multiple stacked sandstone reservoirs. These
reservoirs are developed primarily with vertical wells and
multiple zone completions. We or Memorial Resource operate
317 gross (269 net) producing wells in the Carthage Field,
with an average working interest of 85%.
137
Oil and
Natural Gas Data and Operations Properties
Internal
Controls
The estimates of proved reserve information for all of the
Partnership Properties as of December 31, 2010 included in
this prospectus are based on the following:
(1) approximately 53% of the estimated proved reserve
volumes are based on a reserve report relating to our South
Texas properties prepared by the independent petroleum engineers
of NSAI; (2) approximately 35% of the estimated proved
reserve volumes are based on evaluations relating to certain of
our East Texas properties prepared by Memorial Resources
internal reserve engineers and audited by NSAI; and (3) the
remaining approximately 12% of the estimated proved reserve
volumes are based on a reserve report relating to certain of our
East Texas properties prepared by the independent petroleum
engineers of Miller and Lents.
Our proved reserves were estimated at the well or unit level and
compiled for reporting purposes by our reservoir engineering
staff, NSAI or Miller and Lents. We maintain internal
evaluations of our reserves in a secure reserve engineering
database. The corporate reservoir engineering staff, NSAI and
Miller and Lents interact with our internal petroleum engineers
and geoscience professionals in each of our operating areas and
with operating, accounting and marketing employees to obtain the
necessary data for the reserves estimation process. Following
the consummation of this offering, our reservoir engineering
staff will be independent from our operating teams. Reserves
have been and will be reviewed and approved internally by our
senior management on a semi-annual basis. We anticipate that the
audit committee of our general partners board of directors
will conduct a similar review on a semi-annual basis. We expect
to have our reserve estimates evaluated by NSAI, Miller and
Lents,
and/or
another independent reserve engineering firm, at least annually.
With regard to the approximately 35% of our estimated proved
reserve volumes at December 31, 2010 that were audited by
NSAI, NSAI follows the general principles set forth in the
standards pertaining to the estimating and auditing of oil and
gas reserve information promulgated by the Society of Petroleum
Engineers, or SPE. A reserve audit as defined by the SPE is not
the same as a financial audit. The SPEs definition of a
reserve audit includes the following concepts:
|
|
|
|
|
A reserve audit is an examination of reserve information that is
conducted for the purpose of expressing an opinion as to whether
such reserve information, in the aggregate, is reasonable and
has been presented in conformity with generally accepted
petroleum engineering and evaluation principles.
|
|
|
|
The estimation of proved reserves is an imprecise science due to
the many unknown geologic and reservoir factors that cannot be
estimated through sampling techniques. Since reserves are only
estimates, they cannot be audited for the purpose of verifying
exactness. Instead, reserve information is audited for the
purpose of reviewing in sufficient detail the policies,
procedures and methods used by a company in estimating its
reserves so that the reserve auditors may express an opinion as
to whether, in the aggregate, the reserve information furnished
by a company is reasonable.
|
|
|
|
The methods and procedures used by a company, and the reserve
information furnished by a company, must be reviewed in
sufficient detail to permit the reserve auditor, in its
professional judgment, to express an opinion as to the
reasonableness of the reserve information. The auditing
procedures require the reserve auditor to prepare its own
estimates of reserve information for the audited properties.
|
Our internal professional staff works closely with NSAI and
Miller and Lents to ensure the integrity, accuracy and
timeliness of data that is furnished to them for their reserve
estimation process. All of the reserve information maintained in
our secure reserve engineering database is provided to the
external engineers. In addition, we provide NSAI and Miller and
Lents other pertinent data, such as seismic information,
geologic maps, well logs, production tests, material balance
calculations, well performance data, operating procedures and
relevant economic criteria. We make all requested information,
as well as our pertinent personnel, available to the external
engineers as part of their evaluation of our reserves.
138
Technology
Used to Establish Proved Reserves
Under the SEC rules, proved reserves are those quantities of oil
and natural gas that by analysis of geoscience and engineering
data can be estimated with reasonable certainty to be
economically producible from a given date forward from known
reservoirs, and under existing economic conditions, operating
methods and government regulations. The term reasonable
certainty implies a high degree of confidence that the
quantities of oil and natural gas actually recovered will equal
or exceed the estimate. Reasonable certainty can be established
using techniques that have been proven effective by actual
production from projects in the same reservoir or an analogous
reservoir or by other evidence using reliable technology that
establishes reasonable certainty. Reliable technology is a
grouping of one or more technologies (including computational
methods) that has been field tested and has been demonstrated to
provide reasonably certain results with consistency and
repeatability in the formation being evaluated or in an
analogous formation.
To establish reasonable certainty with respect to our estimated
proved reserves, our internal reserve engineers, NSAI, and
Miller and Lents, as applicable, employed technologies that have
been demonstrated to yield results with consistency and
repeatability. The technologies and economic data used in the
estimation of our proved reserves include, but are not limited
to, electrical logs, radioactivity logs, core analyses, geologic
maps and available downhole and production data, seismic data
and well test data. Reserves attributable to producing wells
with sufficient production history were estimated using
appropriate decline curves or other performance relationships.
Reserves attributable to producing wells with limited production
history and for undeveloped locations were estimated using
performance from analogous wells in the surrounding area and
geologic data to assess the reservoir continuity. These wells
were considered to be analogous based on production performance
from the same formation and completion using similar techniques.
Qualifications
of Responsible Technical Persons
Netherland, Sewell & Associates,
Inc. NSAI is an independent oil and natural
gas consulting firm. No director, officer, or key employee of
NSAI has any financial ownership in us, Memorial Resource, the
Funds, or any of their respective affiliates. NSAIs
compensation for the required investigations and preparation of
its report is not contingent upon the results obtained and
reported. NSAI has not performed other work for us, Memorial
Resource, the Funds, or any of their respective affiliates that
would affect its objectivity.
The estimates of proved reserves at December 31, 2010
presented in the NSAI report, and the engineering audit
presented in the NSAI report relating to the estimates of proved
reserves at December 31, 2010 made by our internal
reservoir engineers, were overseen by Mr. Philip S. (Scott)
Frost, Mr. Justin S. Hamilton, Mr. David E. Nice, and
Mr. Richard (Rick) B. Talley.
Mr. Frost has been practicing consulting petroleum
engineering at NSAI since 1984. Mr. Frost is a Registered
Professional Engineer in the State of Texas and has over
30 years of practical experience in petroleum engineering,
with over 30 years experience in the estimation and
evaluation of reserves. He graduated from Vanderbilt University
in 1979 with a Bachelor of Engineering in Mechanical Engineering
and from Tulane University in 1984 with a Master of Business
Administration Degree.
Mr. Hamilton has been practicing consulting petroleum
engineering at NSAI since 2004. Mr. Hamilton is a
Registered Professional Engineer in the State of Texas and has
over 10 years of practical experience in petroleum
engineering, with over 10 years experience in the
estimation and evaluation of reserves. He graduated from Brigham
Young University in 2000 with a Bachelor of Science Degree in
Mechanical Engineering and from the University of Texas in 2007
with a Master of Business Administration Degree.
Mr. Nice has been practicing consulting petroleum geology
at NSAI since 1998. Mr. Nice is a Certified Petroleum
Geologist and Geophysicist in the State of Texas and has over
26 years of practical experience in petroleum geosciences,
with over 13 years experience in the estimation and
evaluation of reserves. He graduated from University of Wyoming
in 1982 with a Bachelor of Science Degree in Geology and in 1985
with a Master of Science Degree in Geology.
Mr. Talley has been practicing consulting petroleum
engineering at NSAI since 2004. Mr. Talley is a Registered
Professional Engineer in the State of Texas and has over
13 years of practical experience in
139
petroleum engineering, with over seven years experience in the
estimation and evaluation of reserves. He graduated from
University of Oklahoma in 1998 with a Bachelor of Science Degree
in Mechanical Engineering and from Tulane University in 2001
with a Master of Business Administration Degree.
Miller and Lents, Ltd. Miller and Lents
is an independent oil and natural gas consulting firm. No
director, officer, or key employee of Miller and Lents has any
financial ownership in us, Memorial Resource, the Funds, or any
of their respective affiliates. Miller and Lents
compensation for the required investigations and preparation of
its report is not contingent upon the results obtained and
reported. Miller and Lents has not performed other work for us,
Memorial Resource, the Funds, or any of their respective
affiliates that would affect its objectivity.
The estimates of proved reserves at December 31, 2010
presented in the Miller and Lents report was overseen by
Mr. Carl D. Richard. Mr. Richard is an experienced
reservoir engineer having been a practicing petroleum engineer
since 1984. He has more than 25 years of experience in
reserves evaluation. He holds a Bachelor of Science degree in
Petroleum Engineering.
Estimated
Proved Reserves
The following table presents the estimated net proved oil and
natural gas reserves attributable to the Partnership Properties
and the standardized measure amounts associated with the
estimated proved reserves attributable to the Partnership
Properties as of December 31, 2010, based on our reserve
reports. The standardized measure amounts shown in the table are
not intended to represent the current market value of our
estimated oil and natural gas reserves.
|
|
|
|
|
|
|
Partnership
|
|
|
|
Properties as of
|
|
|
|
December 31, 2010
|
|
|
Estimated Proved Reserves
|
|
|
|
|
Oil (MBbls)
|
|
|
2,002
|
|
NGLs (MBbls)
|
|
|
4,502
|
|
Natural gas (MMcf)
|
|
|
285,676
|
|
|
|
|
|
|
Total (MMcfe)(1)
|
|
|
324,697
|
|
Proved developed (MMcfe)
|
|
|
264,572
|
|
Proved undeveloped (MMcfe)
|
|
|
60,125
|
|
Proved developed reserves as a percentage of total proved
reserves
|
|
|
81
|
%
|
Standardized measure (in millions)(2)(3)
|
|
$
|
359.2
|
|
Oil and Natural Gas Prices(4)
|
|
|
|
|
Oil WTI Posting (Plains) per Bbl
|
|
$
|
75.96
|
|
Natural gas NYMEX-Henry Hub per MMBtu
|
|
$
|
4.38
|
|
|
|
|
(1) |
|
Determined using a ratio of six Mcf of natural gas to one Bbl of
oil, condensate or NGLs based on an approximate energy
equivalency. This is an energy content correlation and does not
reflect a value or price relationship between the commodities. |
|
(2) |
|
Standardized measure is the present value of estimated future
net revenues to be generated from the production of proved
reserves, determined in accordance with the rules and
regulations of the SEC without giving effect to non-property
related expenses, such as general and administrative expenses,
interest and income tax expenses, or to depreciation, depletion
and amortization. The future cash flows are discounted using an
annual discount rate of 10%. Because we are a limited
partnership, we are generally not subject to federal income
taxes and thus make no provision for federal income taxes in the
calculation of our standardized measure. Standardized measure
does not give effect to derivative transactions. We expect to
hedge a substantial portion of our future estimated production
from total proved producing reserves. For a description of our
expected commodity derivative contracts, please read
Managements Discussion and |
140
|
|
|
|
|
Analysis of Financial Condition and Results of
Operations Pro Forma Liquidity and Capital
Resources Commodity Derivative Contracts. |
|
(3) |
|
Because we are subject to Texas margin tax, standardized measure
was negatively impacted by $5.0 million. |
|
(4) |
|
Our estimated net proved reserves and related standardized
measure were determined using index prices for oil and natural
gas, without giving effect to derivative contracts, held
constant throughout the life of the properties. These prices
were adjusted by lease for quality, transportation fees,
geographical differentials, marketing bonuses or deductions and
other factors affecting the price received at the wellhead. |
The data in the table above represents estimates only. Oil and
natural gas reserve engineering is inherently a subjective
process of estimating underground accumulations of oil and
natural gas that cannot be measured exactly. The accuracy of any
reserve estimate is a function of the quality of available data
and engineering and geological interpretation and judgment.
Accordingly, reserve estimates may vary from the quantities of
oil and natural gas that are ultimately recovered. For a
discussion of risks associated with internal reserve estimates,
please read Risk Factors Risks Related to Our
Business Our estimated proved reserves and future
production rates are based on many assumptions that may prove to
be inaccurate. Any material inaccuracies in these reserve
estimates or underlying assumptions will materially affect the
quantities and present value of our estimated reserves.
Future prices received for production and costs may vary,
perhaps significantly, from the prices and costs assumed for
purposes of these estimates. The standardized measure amounts
shown above should not be construed as the current market value
of our estimated oil and natural gas reserves. The 10% discount
factor used to calculate standardized measure, which is required
by Financial Accounting Standard Board pronouncements, is not
necessarily the most appropriate discount rate. The present
value, no matter what discount rate is used, is materially
affected by assumptions as to timing of future production, which
may prove to be inaccurate.
Development
of Proved Undeveloped Reserves
As required by SEC rules on reserves disclosure, none of our
proved undeveloped reserves booked at December 31, 2010 are
scheduled to be developed on a date more than five years from
the date the reserves were initially booked as proved
undeveloped. Historically, Memorial Resources drilling and
development programs were substantially funded from its cash
flow from operations. Our expectation is to continue to fund our
drilling and development programs primarily from our cash flow
from operations. Based on our current expectations of our cash
flows and drilling and development programs, which includes
drilling of proved undeveloped locations, we believe that we can
fund the drilling of our current inventory of proved undeveloped
locations and our expansions in the next five years from our
cash flow from operations and, if needed, our new revolving
credit facility. For a more detailed discussion of our pro forma
liquidity position, please read Managements
Discussion and Analysis of Financial Condition and Results of
Operations Pro Forma Liquidity and Capital
Resources.
Because our operations and properties will not be separate from
those of our predecessor until the closing of this offering, we
do not yet have a record of converting our proved undeveloped
reserves to proved developed reserves. For more information
about our predecessors historical costs associated with
the development of proved undeveloped reserves, please read
Note 14 to the historical combined financial statements of
our predecessor as of and for the year ended December 31,
2010.
141
Production,
Revenues and Price History
The following table sets forth information regarding combined
net production of oil and natural gas and certain price and cost
information (i) of our predecessor on a historical basis
and (ii) of us on a pro forma basis for each of the periods
presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Memorial Production Partners LP
|
|
|
Our Predecessor
|
|
Pro Forma
|
|
|
|
|
Year Ended
|
|
Three Months
|
|
|
Year Ended December 31,
|
|
December 31,
|
|
Ended March 31,
|
|
|
2008
|
|
2009
|
|
2010
|
|
2010
|
|
2011
|
|
Production and operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net production volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
59
|
|
|
|
61
|
|
|
|
45
|
|
|
|
107
|
|
|
|
28
|
|
NGLs (MBbls)
|
|
|
83
|
|
|
|
33
|
|
|
|
34
|
|
|
|
272
|
|
|
|
56
|
|
Natural gas (MMcf)
|
|
|
4,719
|
|
|
|
5,282
|
|
|
|
7,314
|
|
|
|
16,713
|
|
|
|
3,897
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
5,569
|
|
|
|
5,847
|
|
|
|
7,792
|
|
|
|
18,985
|
|
|
|
4,399
|
|
Average net production (MMcfe/d)
|
|
|
15
|
|
|
|
16
|
|
|
|
21
|
|
|
|
52
|
|
|
|
49
|
|
Average sales price:(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
100.58
|
|
|
$
|
58.01
|
|
|
$
|
75.81
|
|
|
$
|
74.35
|
|
|
$
|
90.11
|
|
NGLs (per Bbl)
|
|
$
|
18.76
|
|
|
$
|
27.61
|
|
|
$
|
41.02
|
|
|
$
|
37.41
|
|
|
$
|
43.76
|
|
Natural gas (per Mcf)
|
|
$
|
8.87
|
|
|
$
|
3.80
|
|
|
$
|
4.44
|
|
|
$
|
4.17
|
|
|
$
|
4.02
|
|
Average price per Mcfe
|
|
$
|
8.86
|
|
|
$
|
4.20
|
|
|
$
|
4.79
|
|
|
$
|
4.62
|
|
|
$
|
4.69
|
|
Average unit costs per Mcfe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
1.59
|
|
|
$
|
1.92
|
|
|
$
|
1.79
|
|
|
$
|
1.21
|
|
|
$
|
1.52
|
|
Production taxes and ad valorem taxes
|
|
$
|
0.56
|
|
|
$
|
0.25
|
|
|
$
|
0.27
|
|
|
$
|
0.39
|
|
|
$
|
0.39
|
|
General and administrative expenses
|
|
$
|
0.69
|
|
|
$
|
0.82
|
|
|
$
|
0.78
|
|
|
$
|
0.31
|
|
|
$
|
0.32
|
|
Depreciation, depletion and amortization
|
|
$
|
2.22
|
|
|
$
|
2.60
|
|
|
$
|
2.58
|
|
|
$
|
1.83
|
|
|
$
|
1.60
|
|
|
|
|
(1) |
|
Prices do not include the effects of derivative cash settlements. |
Present
Drilling and Other Exploratory and Development
Activities
Drilling Activities. As of
March 31, 2011, our predecessor was in the process of
completing two wells on the Partnership Properties.
Other Exploratory and Development
Activities. As of March 31, 2011, our
predecessor did not have any exploratory activities in progress
on the Partnership Properties.
Predecessor
Drilling and Other Exploratory and Development
Activities
For more information about our predecessors historical
exploratory and development activities, please read
Oil and Natural Gas Data and
Operations Our Predecessor Drilling
Activities. Our predecessors historical exploratory
and development activities should not be considered indicative
of the future performance of our program.
Productive
Wells
The following table sets forth information at March 31,
2011 relating to the productive wells in which we, on a pro
forma basis, owned a working interest as of that date.
Productive wells consist of producing wells and wells capable of
production, including natural gas wells awaiting pipeline
connections to commence deliveries and oil wells awaiting
connection to production facilities. Gross wells are the total
number of
142
producing wells in which we own an interest, and net wells are
the sum of our fractional working interests owned in gross wells.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Operated
|
|
|
4
|
|
|
|
3
|
|
|
|
542
|
|
|
|
422
|
|
Non-operated
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
4
|
|
|
|
3
|
|
|
|
578
|
|
|
|
424
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
Acreage
The following table sets forth information as of March 31,
2011 relating to our pro forma leasehold acreage. Acreage
related to royalty, overriding royalty and other similar
interests is excluded from this summary. As of March 31,
2011, all of our pro forma leasehold acreage was held by
production.
|
|
|
|
|
|
|
|
|
|
|
Developed Acreage(1)
|
|
|
|
Gross(2)
|
|
|
Net(3)
|
|
|
South Texas
|
|
|
82,400
|
|
|
|
72,744
|
|
East Texas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
82,400
|
|
|
|
72,744
|
|
|
|
|
(1) |
|
Developed acres are acres spaced or assigned to productive wells
or wells capable of production. |
|
(2) |
|
A gross acre is an acre in which we own a working interest. The
number of gross acres is the total number of acres in which we
own a working interest. |
|
(3) |
|
A net acre is deemed to exist when the sum of the fractional
ownership working interests in gross acres equals one. The
number of net acres is the sum of the fractional working
interests owned in gross acres expressed as whole numbers and
fractions thereof. |
Delivery
Commitments
We will have no delivery commitments with respect to our
production upon the closing of this offering and the
contribution of the Properties to us.
Oil and
Natural Gas Data and Operations Our
Predecessor
Drilling
Activities
The following table sets forth information with respect to wells
drilled and completed by our predecessor during the periods
indicated. The information should not be considered indicative
of future performance, nor
143
should a correlation be assumed between the number of productive
wells drilled, quantities of reserves found or economic value.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
17.0
|
|
|
|
13.5
|
|
|
|
4.0
|
|
|
|
3.7
|
|
|
|
3.0
|
|
|
|
2.7
|
|
Dry
|
|
|
4.0
|
|
|
|
2.5
|
|
|
|
1.0
|
|
|
|
0.9
|
|
|
|
|
|
|
|
|
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dry
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
17.0
|
|
|
|
13.5
|
|
|
|
4.0
|
|
|
|
3.7
|
|
|
|
3.0
|
|
|
|
2.7
|
|
Dry
|
|
|
4.0
|
|
|
|
2.5
|
|
|
|
1.0
|
|
|
|
0.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
21.0
|
|
|
|
16.0
|
|
|
|
5.0
|
|
|
|
4.6
|
|
|
|
3.0
|
|
|
|
2.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
General
After the completion of this offering we will operate 41% of the
wells and properties containing our proved reserves, and
Memorial Resource will operate substantially all of the other
wells and properties containing our proved reserves. We will
design and manage the development, recompletion
and/or
workover operations, and supervise other operation and
maintenance activities, for all of the wells we operate. We will
not own the drilling rigs or other oil field services equipment
used for drilling or maintaining wells on our properties.
Independent contractors will provide the equipment and personnel
associated with these activities. Pursuant to the omnibus
agreement, Memorial Resource will provide management,
administrative and operating services to our general partner and
us to manage and operate our business. Please read Certain
Relationships and Related Party Transactions
Agreements Governing the Transactions Omnibus
Agreement for more information about the omnibus agreement.
Oil
and Natural Gas Leases
The typical oil and natural gas lease agreement covering our
properties provides for the payment of royalties to the mineral
owner for all oil and natural gas produced from any well drilled
on the lease premises. The lessor royalties and other leasehold
burdens on the Partnership Properties range from 0% to 59%, or
19% on average, resulting in a net revenue interest to us
ranging from 41% to 100%. Most of our leases are held by
production and do not require lease rental payments.
Marketing
and Major Customers
The production sales agreements covering our properties contain
customary terms and conditions for the oil and natural gas
industry and provide for sales based on prevailing market
prices. A majority of those agreements have terms that renew on
a
month-to-month
basis until either party gives advance written notice of
non-renewal.
For the year ended December 31, 2010, purchases by
Enterprise Texas Pipeline, LLC, Dominion Gas Ventures, LP, and
ConocoPhillips, accounted for approximately 31%, 25% and 11%,
respectively, of our predecessors total sales revenues.
Enterprise Texas Pipeline, Dominion Gas Ventures, and
ConocoPhillips purchase the oil production from our predecessor
pursuant to existing marketing agreements with terms that are
currently on evergreen status and renew on a
month-to-month
basis until either party gives
30-day
advance written notice of non-renewal.
144
If we were to lose any one of our customers, the loss could
temporarily delay production and sale of our oil and natural gas
in the related producing region. If we were to lose any single
customer, we believe we could identify a substitute customer to
purchase the impacted production volumes. However, if one or
more of our larger customers ceased purchasing oil or natural
gas altogether, the loss of such could have a detrimental effect
on our production volumes in general and on our ability to find
substitute customers to purchase our production volumes.
Competition
We operate in a highly competitive environment for acquiring
properties and securing qualified personnel. Many of our
competitors possess and employ financial, technical and
personnel resources substantially greater than ours, which can
be particularly important in the areas in which we operate. As a
result, our competitors may be able to pay more for productive
oil and natural gas properties and exploratory prospects, as
well as evaluate, bid for and purchase a greater number of
properties and prospects than our financial or personnel
resources permit. Our ability to acquire additional properties
and to find and develop reserves will depend on our ability to
evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. In addition,
there is substantial competition for capital available for
investment in the oil and natural gas industry.
We are also affected by competition for drilling rigs,
completion rigs, workover rigs, completion services and the
availability of related equipment. In recent years, the United
States onshore oil and natural gas industry has experienced
shortages of drilling and completion rigs, equipment, pipe and
personnel, which have delayed development drilling and other
exploitation activities and caused significant increases in the
prices for this equipment and personnel. We are unable to
predict when, or if, such shortages may occur or how they would
affect our development and exploitation programs.
In addition, Memorial Resource and the Funds and their
respective affiliates (including NGP and its affiliates
portfolio investments) are not restricted from competing with us
and such entities could be competing producers in all of our
operating areas, as well as competitors for acquisition
opportunities. Please read Our Principal
Business Relationships and Certain Relationships and
Related Party Transactions and Risk
Factors Risks Inherent in an Investment in
Us Memorial Resource, the Funds and other affiliates
of our general partner will not be limited in their ability to
compete with us, which could cause conflicts of interest and
limit our ability to acquire additional assets or
businesses.
Title
to Properties
Memorial Resource has previously performed title reviews on
significant leases included in the Partnership Properties and,
depending on the materiality of properties, obtained a title
opinion or reviewed previously obtained title opinions. As a
result, title examinations have been obtained on a significant
portion of our properties.
We believe that we have satisfactory title to all of our
material assets. Although title to these properties is subject
to encumbrances in some cases, such as customary interests
generally retained in connection with the acquisition of real
property, customary royalty interests and contract terms and
restrictions, liens under operating agreements, liens related to
environmental liabilities associated with historical operations,
liens for current taxes and other burdens, easements,
restrictions and minor encumbrances customary in the oil and
natural gas industry, we believe that none of these liens,
restrictions, easements, burdens and encumbrances will
materially detract from the value of these properties or from
our interest in these properties or materially interfere with
our use of these properties in the operation of our business. In
addition, we believe that we have obtained sufficient
rights-of-way
grants and permits from public authorities and private parties
for us to operate our business in all material respects as
described in this prospectus.
145
Seasonal
Nature of Business
Generally, but not always, the demand for natural gas decreases
during the summer months and increases during the winter months,
resulting in seasonal fluctuations in the price we receive for
our natural gas production. Seasonal anomalies such as mild
winters or hot summers sometimes lessen this fluctuation.
Environmental
Matters and Regulation
General
Our operations are subject to stringent and complex federal,
state and local laws and regulations governing environmental
protection as well as the discharge of materials into the
environment. These laws and regulations may, among other things
(i) require the acquisition of permits to conduct
exploration, drilling and production operations;
(ii) restrict the types, quantities and concentration of
various substances that can be released into the environment or
injected into formations in connection with oil and natural gas
drilling and production activities; (iii) limit or prohibit
drilling activities on certain lands lying within wilderness,
wetlands and other protected areas; (iv) require remedial
measures to mitigate pollution from former and ongoing
operations, such as requirements to close pits and plug
abandoned wells; and (v) impose substantial liabilities for
pollution resulting from drilling and production operations. Any
failure to comply with these laws and regulations may result in
the assessment of administrative, civil, and criminal penalties,
the imposition of corrective or remedial obligations, and the
issuance of orders enjoining performance of some or all of our
operations.
These laws and regulations may also restrict the rate of oil and
natural gas production below the rate that would otherwise be
possible. The regulatory burden on the oil and natural gas
industry increases the cost of doing business in the industry
and consequently affects profitability. Additionally, the
Congress and federal and state agencies frequently revise
environmental laws and regulations, and any changes that result
in more stringent and costly waste handling, disposal and
cleanup requirements for the oil and natural gas industry could
have a significant impact on our operating costs.
The clear trend in environmental regulation is to place more
restrictions and limitations on activities that may affect the
environment, and thus any changes in environmental laws and
regulations or re-interpretation of enforcement policies that
result in more stringent and costly waste handling, storage
transport, disposal, or remediation requirements could have a
material adverse effect on our financial position and results of
operations. We may be unable to pass on such increased
compliance costs to our customers. Moreover, accidental releases
or spills may occur in the course of our operations, and we
cannot assure you that we will not incur significant costs and
liabilities as a result of such releases or spills, including
any third-party claims for damage to property, natural resources
or persons. While we believe that we are in substantial
compliance with existing environmental laws and regulations and
that continued compliance with existing requirements will not
materially affect us, there is no assurance that this trend will
continue in the future.
The following is a summary of the more significant existing
environmental, health and safety laws and regulations to which
our business operations are subject and for which compliance may
have a material adverse impact on our capital expenditures,
results of operations or financial position.
Hazardous
Substances and Waste
The Resource Conservation and Recovery Act, as amended, or RCRA,
and comparable state statutes and their implementing
regulations, regulate the generation, transportation, treatment,
storage, disposal and cleanup of hazardous and non-hazardous
wastes. Under the auspices of the U.S. Environmental
Protection Agency, or EPA, most states administer some or all of
the provisions of RCRA, sometimes in conjunction with their own,
more stringent requirements. Federal and state regulatory
agencies can seek to impose administrative, civil and criminal
penalties for alleged non-compliance with RCRA and analogous
state requirements. Drilling fluids, produced waters, and most
of the other wastes associated with the exploration,
development, and production of oil or natural gas, if properly
handled, are exempt from regulation as hazardous waste under
Subtitle C of RCRA. These wastes, instead, are regulated under
RCRAs less stringent solid waste provisions, state laws or
146
other federal laws. However, it is possible that certain oil and
natural gas exploration, development and production wastes now
classified as non-hazardous could be classified as hazardous
wastes in the future. In particular, the materials used in
hydraulic fracturing, as well as its byproducts, could be
classified as hazardous wastes. Any such change could result in
an increase in our costs to manage and dispose of wastes, which
could have a material adverse effect on our results of
operations and financial position.
The Comprehensive Environmental Response, Compensation and
Liability Act, as amended, or CERCLA, also known as the
Superfund law, and comparable state laws impose
strict and joint and several liability, without regard to fault
or legality of the original conduct, on classes of persons
considered to be responsible for the release of a
hazardous substance into the environment. These
persons include the current and past owner or operator of the
site where the release occurred, and anyone who disposed or
arranged for the disposal of a hazardous substance released at
the site. Under CERCLA and comparable state statutes, such
persons deemed responsible parties may be subject to
joint and several, strict liability for removing or remediating
previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination
(including groundwater contamination), for damages to natural
resources and for the costs of certain health studies. In
addition, neighboring landowners and other third-parties may
file claims for personal injury and property damage allegedly
caused by the hazardous substances released into the
environment. We generate materials in the course of our
operations that may be regulated as hazardous substances.
We currently own, lease, or operate numerous properties that
have been used for oil and natural gas exploration, production
and processing for many years. Although we believe that we have
utilized operating and waste disposal practices that were
standard in the industry at the time, hazardous substances,
wastes, or hydrocarbons may have been released on, under or from
the properties owned or leased by us, or on, under or from other
locations, including off-site locations, where such substances
have been taken for disposal. In addition, some of our
properties have been operated by third parties or by previous
owners or operators whose treatment and disposal of hazardous
substances, wastes, or hydrocarbons was not under our control.
These properties and the substances disposed or released on,
under or from them may be subject to CERCLA, RCRA, and analogous
state laws. Under such laws, we could be required to undertake
response or corrective measures, which could include removal of
previously disposed substances and wastes, cleanup of
contaminated property or performance of remedial plugging or pit
closure operations to prevent future contamination.
Water
Discharges
The Clean Water Act, in the Federal Water Pollution Control Act,
as amended, and analogous state laws, impose restrictions and
strict controls with respect to the unauthorized discharge of
pollutants, including oil and hazardous substances, into
navigable waters of the United States, as well as state waters.
The discharge of pollutants into regulated waters is prohibited,
except in accordance with the terms of a permit issued by EPA or
an analogous state agency. These laws and regulations also
prohibit certain activity in wetlands unless authorized by a
permit issued by the U.S. Army Corps of Engineers. Federal
and state regulatory agencies can impose administrative, civil
and criminal penalties for non-compliance with discharge permits
or other requirements of the Clean Water Act and analogous state
laws and regulations. Spill prevention, control and
countermeasure, or SPCC, plan requirements imposed under the
Clean Water Act require appropriate containment berms and
similar structures to help prevent the contamination of
navigable waters in the event of a hydrocarbon tank spill,
rupture or leak. In addition, the Clean Water Act and analogous
state laws required individual permits or coverage under general
permits for discharges of storm water runoff from certain types
of facilities. Costs may be associated with the treatment of
wastewater or developing and implementing storm water pollution
prevention plans, as well as for monitoring and sampling the
storm water runoff from certain of our facilities. Some states
also maintain groundwater protection programs that require
permits for discharges or operations that may impact groundwater
conditions.
The Oil Pollution Act of 1990, as amended, or OPA, amends the
Clean Water Act and contains numerous requirements relating to
the prevention of and response to petroleum releases into waters
of the United States, including the requirement that operators
of offshore facilities and certain onshore facilities near or
crossing
147
waterways must maintain certain significant levels of financial
assurance to cover potential environmental cleanup and
restoration costs. The OPA subjects owners of facilities to
strict, joint and several liability for all containment and
cleanup costs and certain other damages arising from a release,
including, but not limited to, the costs of responding to a
release of oil to surface waters. OPA also requires owners or
operators of certain onshore facilities to prepare Facility
Response Plans for responding to a worst case discharge of oil
into waters of the United States.
It is customary to recover natural gas from deep shale
formations through the use of hydraulic fracturing, combined
with sophisticated horizontal drilling. Hydraulic fracturing
involves the injection of water, sand and chemical additives
under pressure into rock formations to stimulate natural gas
production. Due to public concerns raised regarding the
potential impacts of hydraulic fracturing on groundwater
quality, legislative and regulatory efforts at the federal level
and in some states have been initiated to require or make more
stringent the permitting and compliance requirements for
hydraulic fracturing operations. In particular, the
U.S. Senate and House of Representatives are currently
considering bills entitled, the Fracturing Responsibility
and Awareness of Chemicals Act, or the FRAC Act, to amend
the federal Safe Drinking Water Act, or the SDWA, to repeal an
exemption from regulation for hydraulic fracturing. If enacted,
the FRAC Act would amend the definition of underground
injection in the SDWA to encompass hydraulic fracturing
activities, requiring hydraulic fracturing operations to meet
permitting and financial assurance requirements, adhere to
certain construction specifications, fulfill monitoring,
reporting, and recordkeeping obligations, and meet plugging and
abandonment requirements. The FRAC Act also proposes to require
the reporting and public disclosure of chemicals used in the
fracturing process. In unrelated oil spill legislation being
considered by the U.S. Senate in the aftermath of the April
2010 Macondo well release in the Gulf of Mexico, Senate Majority
Leader Harry Reid has added a requirement that natural gas
drillers disclose the chemicals they pump into the ground as
part of the hydraulic fracturing process. Disclosure of
chemicals used in the hydraulic fracturing process could make it
easier for third parties opposing the hydraulic fracturing
process to initiate legal proceedings based on allegations that
specific chemicals used in the fracturing process could
adversely affect groundwater. Adoption of legislation or of any
implementing regulations placing restrictions on hydraulic
fracturing activities could impose operational delays, increased
operating costs and additional regulatory burdens on our
exploration and production activities, which could make it more
difficult to perform hydraulic fracturing and increase our costs
of compliance and doing business.
Air
Emissions
The federal Clean Air Act, as amended, and comparable state
laws, regulate emissions of various air pollutants through air
emissions standards, construction and operating permitting
programs and the imposition of other compliance requirements.
The EPA has developed, and continues to develop, stringent
regulations governing emissions of air pollutants at specified
sources. These laws and regulations may require us to obtain
pre-approval for the construction or modification of certain
projects or facilities expected to produce or significantly
increase air emissions, obtain and strictly comply with
stringent air permit requirements or utilize specific equipment
or technologies to control emissions. The need to obtain permits
has the potential to delay the development of oil and natural
gas projects. These laws and regulations also may increase the
costs of compliance for some facilities we own or operate, and
federal and state regulatory agencies can impose administrative,
civil and criminal penalties for non-compliance with air permits
or other requirements of the federal Clean Air Act and
associated state laws and regulations. Although we may be
required to incur certain capital expenditures in the next few
years for air pollution control equipment or other air
emissions-related issues, we do not believe that such
requirements will have a material adverse effect on our
operations.
Climate
Change
On April 2, 2007, the U.S. Supreme Court ruled, in
Massachusetts, et al. v. EPA, that the federal Clean Air
Act definition of pollutant includes carbon dioxide
and other GHGs and, therefore, EPA has the authority to regulate
carbon dioxide emissions from automobiles. Thereafter, on
December 15, 2009, the EPA published its findings that
emissions of carbon dioxide, or
CO2,
methane, and other greenhouse gases, or GHGs, present an
endangerment to public health and the environment because
emissions of such gases are, according to the EPA, contributing
to the warming of the earths atmosphere and other climate
changes. These
148
findings allowed the EPA to adopt and implement regulations that
would restrict emissions of GHGs under existing provisions of
the federal Clean Air Act. The EPA has adopted two sets of
regulations under the Clean Air Act. The first limits emissions
of GHGs from motor vehicles beginning with the 2012 model year.
The EPA has asserted that these final motor vehicle GHG emission
standards trigger Clean Air Act construction and operating
permit requirements for stationary sources, commencing when the
motor vehicle standards take effect on January 2, 2011. On
June 3, 2010, the EPA published its final rule to address
the permitting of GHG emissions from stationary sources under
the Prevention of Significant Deterioration, or PSD,
and Title V permitting programs. This rule
tailors these permitting programs to apply to
certain stationary sources of GHG emissions in a multi-step
process, with the largest sources first subject to permitting.
It is widely expected that facilities required to obtain PSD
permits for their GHG emissions also will be required to reduce
those emissions according to best available control
technology standards for GHG that have yet to be
developed. Additionally, EPA requires reporting of GHG emissions
from certain large emissions sources. In October 2009, the EPA
published a final rule requiring the reporting of GHG emissions
from specified large GHG emission sources in the U.S., including
natural gas liquids fractionators and local natural
gas/distribution companies, beginning in 2011 for emissions
occurring in 2010. In November 2010, the EPA issued a final rule
expanding its existing GHG reporting rule to include onshore oil
and natural gas production, processing, transmission, storage,
and distribution facilities. The final rule, which may be
applicable to many of our facilities, will require reporting of
GHG emissions from such facilities on an annual basis, with
reporting beginning in 2012 for emissions occurring in 2011.
In June 2009, the U.S. House of Representatives passed the
American Clean Energy and Security (ACES) Act that, among other
things, would have established a
cap-and-trade
system to regulate greenhouse gas emissions and would have
required an 80% reduction in GHG emissions from sources within
the United States between 2012 and 2050. The ACES Act did not
pass the Senate, however, and so was not enacted by the
111th Congress. The United States Congress is likely to
consider again a climate change bill in the future. In addition,
one-half of the states have already taken legal measures to
reduce emissions of GHGs, primarily through the planned
development of GHG emission inventories
and/or
regional GHG cap and trade programs. Most of these cap and trade
programs work by requiring either major sources of emissions or
major producers of fuels to acquire and surrender emission
allowances, with the number of allowances available for purchase
reduced each year until the overall GHG emission reduction goal
is achieved. The adoption of any legislation or regulations that
requires reporting of GHGs or otherwise limits emissions of GHGs
from our equipment and operations could require us to incur
costs to monitor and report on GHG emissions or reduce emissions
of GHGs associated with our operations, and such requirements
also could adversely affect demand for the oil and natural gas
that we produce.
Finally, it should be noted that some scientists have concluded
that increasing concentrations of greenhouse gases in the
Earths atmosphere may produce climate changes that have
significant physical effects, such as increased frequency and
severity of storms, droughts, and floods and other climatic
events. If any such effects were to occur in areas where we
operate, they could have in adverse effect on our assets and
operations.
National
Environmental Policy Act
Oil and natural gas exploration, development and production
activities on federal lands are subject to the National
Environmental Policy Act, as amended, or NEPA. NEPA requires
federal agencies, including the Department of Interior, to
evaluate major agency actions having the potential to
significantly impact the environment. In the course of such
evaluations, an agency will prepare an Environmental Assessment
that assesses the potential direct, indirect and cumulative
impacts of a proposed project and, if necessary, will prepare a
more detailed Environmental Impact Statement that may be made
available for public review and comment. Currently, we have
minimal exploration and production activities on federal lands.
However, for those current activities as well as for future or
proposed exploration and development plans on federal lands
governmental permits or authorizations that are subject to the
requirements of NEPA are required. This process has the
potential to delay the development of oil and natural gas
projects.
149
Endangered
Species Act
Environmental laws such as the Endangered Species Act, as
amended, or ESA, may impact exploration, development and
production activities on public or private lands. The ESA
provides broad protection for species of fish, wildlife and
plants that are listed as threatened or endangered in the U.S.,
and prohibits taking of endangered species. Federal agencies are
required to insure that any action authorized, funded or carried
out by them is not likely to jeopardize the continued existence
of listed species or modify their critical habitat. Although
some of our facilities may be located in areas that are
designated as habitat for endangered or threatened species, we
believe that we are in substantial compliance with the ESA.
However, the designation of previously unidentified endangered
or threatened species could cause us to incur additional costs
or become subject to operating restrictions or bans in the
affected areas.
OSHA
We are subject to the requirements of the federal Occupational
Safety and Health Act, as amended, or OSHA, and comparable state
statutes whose purpose is to protect the health and safety of
workers. In addition, the OSHA hazard communication standard,
the Emergency Planning and Community Right to Know Act and
implementing regulations, and similar state statutes and
regulations require that we organize
and/or
disclose information about hazardous materials used or produced
in our operations and that this information be provided to
employees, state and local governmental authorities and
citizens. We believe that we are in substantial compliance with
all applicable laws and regulations relating to worker health
and safety.
Other
Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by
numerous federal, state and local authorities. Legislation
affecting the oil and natural gas industry is under constant
review for amendment or expansion, frequently increasing the
regulatory burden. Additionally, numerous departments and
agencies, both federal and state, are authorized by statute to
issue rules and regulations that are binding on the oil and
natural gas industry and its individual members, some of which
carry substantial penalties for failure to comply. Although the
regulatory burden on the oil and natural gas industry increases
our cost of doing business and, consequently, affects our
profitability, these burdens generally do not affect us any
differently or to any greater or lesser extent than they affect
other companies in the oil and natural gas industry with similar
types, quantities and locations of production.
Legislation continues to be introduced in Congress, and the
development of regulations continues in the Department of
Homeland Security and other agencies concerning the security of
industrial facilities, including oil and natural gas facilities.
Our operations may be subject to such laws and regulations.
Presently, we do not believe that compliance with these laws
will have a material adverse impact on us.
Drilling
and Production
Our operations are subject to various types of regulation at
federal, state and local levels. These types of regulation
include requiring permits for the drilling of wells, drilling
bonds and reports concerning operations. Most states, and some
counties and municipalities, in which we operate also regulate
one or more of the following:
|
|
|
|
|
the location of wells;
|
|
|
|
the method of drilling and casing wells;
|
|
|
|
the surface use and restoration of properties upon which wells
are drilled;
|
|
|
|
the plugging and abandoning of wells; and
|
|
|
|
notice to surface owners and other third parties.
|
150
State laws regulate the size and shape of drilling and spacing
units or proration units governing the pooling of oil and
natural gas properties. Some states allow forced pooling or
integration of tracts to facilitate exploration, while other
states rely on voluntary pooling of lands and leases. In some
instances, forced pooling or unitization may be implemented by
third parties and may reduce our interest in the unitized
properties. In addition, state conservation laws establish
maximum rates of production from oil and natural gas wells,
generally prohibit the venting or flaring of natural gas and
impose requirements regarding the ratability of production.
These laws and regulations may limit the amount of oil and
natural gas we can produce from our wells or limit the number of
wells or the locations at which we can drill. Moreover, each
state generally imposes a production or severance tax with
respect to the production and sale of oil, natural gas and NGLs
within its jurisdiction.
Natural
Gas Regulation
The availability, terms and cost of transportation significantly
affect sales of natural gas. The interstate transportation and
sale for resale of natural gas is subject to federal regulation,
including regulation of the terms, conditions and rates for
interstate transportation, storage and various other matters,
primarily by the Federal Energy Regulatory Commission. Federal
and state regulations govern the price and terms for access to
natural gas pipeline transportation. The Federal Energy
Regulatory Commissions regulations for interstate natural
gas transmission in some circumstances may also affect the
intrastate transportation of natural gas.
Although natural gas prices are currently unregulated, Congress
historically has been active in the area of natural gas
regulation. We cannot predict whether new legislation to
regulate natural gas might be proposed, what proposals, if any,
might actually be enacted by Congress or the various state
legislatures, and what effect, if any, the proposals might have
on the operations of our properties. Sales of condensate and
NGLs are not currently regulated and are made at market prices.
State Regulation. The various states
regulate the drilling for, and the production, gathering and
sale of, oil and natural gas, including imposing severance taxes
and requirements for obtaining drilling permits. For example,
Texas currently imposes a 4.6% severance tax on oil production
and a 7.5% severance tax on natural gas production. States also
regulate the method of developing new fields, the spacing and
operation of wells and the prevention of waste of natural gas
resources. States may regulate rates of production and may
establish maximum daily production allowables from natural gas
wells based on market demand or resource conservation, or both.
States do not regulate wellhead prices or engage in other
similar direct economic regulation, but there can be no
assurance that they will not do so in the future. The effect of
these regulations may be to limit the amount of natural gas that
may be produced from our wells and to limit the number of wells
or locations we can drill.
The petroleum industry is also subject to compliance with
various other federal, state and local regulations and laws.
Some of those laws relate to resource conservation and equal
employment opportunity. We do not believe that compliance with
these laws will have a material adverse effect on us.
Employees
The directors and officers of our general partner will manage
our operations and activities. However, neither we, our
subsidiaries, nor our general partner have employees.
Immediately prior to the closing of this offering, we and our
general partner will enter into an omnibus agreement with
Memorial Resource pursuant to which Memorial Resource will
perform services for us, including the operation of our
properties. Please read Certain Relationships and Related
Party Transactions Agreements Governing the
Transactions Omnibus Agreement.
As of May 31, 2011, Memorial Resource had
104 employees, including 50 engineers, geologists and land
professionals. None of these employees are represented by labor
unions or covered by any collective bargaining agreement. We
believe that Memorial Resources relations with its
employees are satisfactory. Our
151
general partner will also contract on our behalf for the
services of independent consultants involved in land,
engineering, regulatory, accounting, financial and other
disciplines as needed.
Offices
For our principal offices, we currently lease
approximately square feet of office space in
Houston, Texas
at .
The lease expires
on .
Legal
Proceedings
Although we may, from time to time, be involved in litigation
and claims arising out of our operations in the normal course of
business, we are not currently a party to any material legal
proceedings. In addition, we are not aware of any significant
legal or governmental proceedings against us, or contemplated to
be brought against us, under the various environmental
protection statutes to which we are subject.
152
MANAGEMENT
Management
of Memorial Production Partners LP
Memorial Production Partners GP LLC, our general partner, will
manage our operations and activities on our behalf. Our general
partner is a wholly-owned subsidiary of Memorial Resource. All
of our executive management personnel are employees of Memorial
Resource and will devote their time as needed to conduct our
business and affairs.
The executive officers of our general partner will allocate
their time between managing our business and affairs and the
business and affairs of Memorial Resource. The executive
officers of our general partner may face a conflict regarding
the allocation of their time between our business and the other
business interests of Memorial Resource. We expect that the
officers of our general partner will initially devote a
significant amount of their time to our business, although we
expect the amount of time that they devote may increase or
decrease in future periods as our business develops. These
officers of our general partner and other Memorial Resource
employees will operate our business and provide us with
operating and general and administrative services pursuant to
the omnibus agreement described in Certain Relationships
and Related Party Transactions Agreements Governing
the Transactions Omnibus Agreement. We will
reimburse Memorial Resource for allocated expenses of
operational personnel who perform services for our benefit, as
well as all other expenses incurred on our behalf.
Our general partner is not elected by our unitholders and will
not be subject to re-election on a regular basis in the future.
Unitholders will not be entitled to elect the directors of our
general partner or directly or indirectly participate in our
management or operation. Our partnership agreement contains
provisions that reduce the fiduciary duties that our general
partner owes to our unitholders. Please read Conflicts of
Interest and Fiduciary Duties Fiduciary
Duties. Our general partner will be liable, as general
partner, for all of our debts (to the extent not paid from our
assets), except for indebtedness or other obligations that are
made specifically nonrecourse to it. Whenever possible, our
general partner intends to cause us to incur indebtedness or
other obligations that are nonrecourse to it. Except as
described in The Partnership Agreement Limited
Voting Rights and subject to its fiduciary duty to act in
good faith, our general partner will have exclusive management
power over our business and affairs.
Our general partner has a board of directors that oversees its
management, operations and activities. At the closing of this
offering, the board of directors will have five members, one of
whom will be independent as defined under the independence
standards established by NASDAQ and SEC rules. This director, to
whom we refer to as an independent director, will not be an
officer or employee of our general partner or its affiliates,
and will otherwise be independent of Memorial Resource and its
affiliates. Within 90 days of the date our common units are
listed on NASDAQ, the board of directors will have at least one
additional independent director, and within one year of such
listing date, the board of directors of our general partner will
have at least three independent directors. Because we are a
limited partnership, we are not required to have a majority of
independent directors on the board of directors of our general
partner or to establish a compensation committee or a nominating
and corporate governance committee.
The board of directors of our general partner will have a
conflicts committee to review specific matters that the board of
directors believes may involve conflicts of interest and which
it determines to submit to the conflicts committee for review.
Every member of the conflicts committee must not be an officer
or employee of our general partner or its affiliates, must
otherwise be independent of our general partner and its
affiliates (including Memorial Resource and NGP), and must meet
the independence standards established by the NASDAQ Marketplace
Rules and the Securities Exchange Act of 1934 to serve on an
audit committee of a board of directors. At the closing of this
offering, the conflicts committee will consist of one director.
Within one year of the closing of this offering, we intend that
the conflicts committee will consist of at least two directors.
Under our partnership agreement, our conflicts committee has
responsibility for (i) approving the amount of estimated
maintenance capital expenditures deducted from operating
surplus; and (ii) the approval of the allocation of capital
expenditures between maintenance capital expenditures,
investment capital expenditures and growth capital expenditures.
Other than these enumerated responsibilities, our general
partner may, but is not
153
required to, seek approval from the conflicts committee
regarding a resolution of a conflict of interest with our
general partner or affiliates. The conflicts committee will
determine if the resolution of the conflict of interest is fair
and reasonable to us. Any matters approved by the conflicts
committee will be conclusively deemed to be fair and reasonable
to us, approved by all of our partners and not a breach by our
general partner of any duties it may owe us or our unitholders.
Please read Conflicts of Interest and Fiduciary
Duties Conflicts of Interest.
At the closing of this offering, our general partner will have
an audit committee consisting of three directors, one of whom
will meet the independence and experience standards established
by the NASDAQ Marketplace Rules and the Securities Exchange Act
of 1934. Within 90 days of the closing of this offering,
the audit committee will substitute one director meeting such
standards for one of the non-independent directors on the audit
committee and, within one year of the closing of this offering,
the audit committee will consist of at least three directors,
all of whom will meet such standards. The audit committee will
assist the board of directors in its oversight of the integrity
of our financial statements and our compliance with legal and
regulatory requirements and partnership policies and controls.
The audit committee will have the sole authority to retain and
terminate our independent registered public accounting firm,
approve all auditing services and related fees and the terms
thereof, and pre-approve any non-audit services to be rendered
by our independent registered public accounting firm. The audit
committee will also be responsible for confirming the
independence and objectivity of our independent registered
public accounting firm. Our independent registered public
accounting firm will be given unrestricted access to the audit
committee.
Generally, the executive officers of our general partner listed
below will allocate their time between managing our business and
affairs and the business and affairs of Memorial Resource. The
executive officers of our general partner may face a conflict
regarding the allocation of their time between our business and
the other business interests of Memorial Resource. Memorial
Resource intends to cause the executive officers to devote as
much time to the management of our business and affairs as is
necessary for the proper conduct of our business and affairs,
although it is anticipated that the executive officers of our
general partner will devote a significant amount of their time
to our business for the foreseeable future. We will also use a
significant number of other employees of Memorial Resource to
operate our business and provide us with general and
administrative services. Please read Certain Relationships
and Related Party Transactions Agreements Governing
the Transactions Omnibus Agreement.
Board
Leadership Structure and Role in Risk Oversight
Leadership of our general partners board of directors is
vested in a Chairman of the board. John A. Weinzierl will serve
as our Chairman of the board and President and Chief Executive
Officer of our general partner. Our general partners board
of directors has determined that the combined roles of Chairman
and Chief Executive Officer will allow the board to take
advantage of the leadership skills of Mr. Weinzierl and is
appropriate because Mr. Weinzierl works closely with our
management team on a daily basis and is in the most
knowledgeable position to determine the timing for board
meetings and propose agendas for meetings. However, any director
can establish agenda items for a board meeting.
Mr. Weinzierls in-depth knowledge of, and experience
in, our business, history, structure and organization
facilitates timely communications between our general
partners management and the board. Our general
partners board of directors has also determined that
having the Chief Executive Officer serve as a director enhances
understanding and communication between management and the board
of directors, allows for better comprehension and evaluation of
our operations and ultimately improves the ability of the board
of directors to perform its oversight role. In addition,
maintaining the combined Chairman and Chief Executive Officer
positions contributes to a consistent strategy and direction for
the Partnership and the investing public by alleviating
potential ambiguities in the decision-making process. Our
general partner will not initially have a lead independent
director.
The management of enterprise-level risk may be defined as the
process of identifying, managing and monitoring events that
present opportunities and risks with respect to the creation of
value for our unitholders. The board of directors of our general
partner has delegated to management the primary responsibility
for enterprise-level risk management, while the board has
retained responsibility for oversight of management in that
regard. Our executive officers will offer an enterprise-level
risk assessment to the board of directors at least once every
year.
154
Directors
and Executive Officers
The following table sets forth certain information regarding the
current directors and executive officers of our general partner.
Directors are elected for one-year terms.
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position with Our General Partner
|
|
John A. Weinzierl
|
|
|
43
|
|
|
President, Chief Executive Officer, and Chairman
|
Andrew J. Cozby
|
|
|
44
|
|
|
Vice President, Finance
|
Patrick T. Nguyen
|
|
|
38
|
|
|
Chief Accounting Officer
|
Gregory M. Robbins
|
|
|
32
|
|
|
Treasurer
|
Kenneth A. Hersh
|
|
|
48
|
|
|
Director
|
Our general partners directors hold office until the
earlier of their death, resignation, removal or disqualification
or until their successors have been elected and qualified.
Officers serve at the discretion of the board of directors. In
selecting and appointing directors to the board of directors,
the owners of our general partner do not intend to apply a
formal diversity policy or set of guidelines. However, when
appointing new directors, the owners of our general partner will
consider each individual directors qualifications, skills,
business experience and capacity to serve as a director, as
described below for each director, and the diversity of these
attributes for the board of directors as a whole.
John A. Weinzierl has served as our general
partners President, Chief Executive Officer and Chairman
of the board of directors since April 2011. Until the completion
of this offering, Mr. Weinzierl was a managing director and
operating partner of NGP. Prior to this role Mr. Weinzierl
was a managing director and served in this capacity since 2004.
Mr. Weinzierl served as a senior associate at NGP from 1999
until 2000, and then as a principal until 2004. Prior to joining
NGP, Mr. Weinzierl was an associate in the Capital and
Trade Resources division of Enron Corp. Before he joined Enron,
Mr. Weinzierl worked for Conoco, Inc. as a petroleum
engineer. Mr. Weinzierl has served as a director for
numerous private and public companies. He currently serves as a
director for several of NGPs private portfolio companies
and as a director of Eagle Rock Energy G&P, LLC, where he
is on the compensation committee. Mr. Weinzierl holds a
B.S. in petroleum engineering and an M.B.A. from the University
of Texas at Austin and is a registered professional engineer in
Texas.
The board believes Mr. Weinzierls degree and
experience in petroleum engineering, his M.B.A. education, as
well as his investment and business expertise honed at NGP
brings valuable strategic, managerial and analytical skills to
the board and us.
Andrew J. Cozby has served as our general
partners Vice President of Finance since April 2011. From
February 2011 to April 2011, Mr. Cozby served as Senior
Vice President and Chief Financial Officer of Energy Maintenance
Services (EMS Global). Prior to that, he was Chief Financial
Officer of Greystone Oil & Gas LLP and Greystone
Drilling LP from 2006 to 2010. From 2000 to 2006, Mr. Cozby
was Director of Finance for Enterprise Products Partners LP and
held various corporate finance positions with its affiliates
GulfTerra Energy Partners, LP and El Paso Energy Partners,
LP. Prior to that, Mr. Cozby held positions with
J.P. Morgan from 1998 to 2000. Mr. Cozby holds a
B.B.A. in finance from the University of Texas and an M.B.A. in
finance from the University of Houston. He is also a graduate of
Texas Tech University (J.D.), the University of Houston (LL.M.,
energy and natural resources law) and Harvard Business School
(advanced management program).
Patrick T. Nguyen has served as our general
partners Chief Accounting Officer since June 2011. Prior
to joining our general partner, Mr. Nguyen was with
Enterprise Products Partners LP from June 2007 to May 2011 as
Director of Financial Accounting and Director of Accounts
Receivable and Accounts Payable. From 1996 to 2007, he held
positions in financial accounting and reporting within
El Paso Corporations midstream segment, El Paso
Field Services Company and its affiliates GulfTerra Energy
Partners, LP and El Paso Energy Partners, LP. Prior to
that, he worked at BHP Billiton as a joint venture and general
ledger accountant. Mr. Nguyen holds a B.B.A. in Accounting
and Taxation from the University of Houston and a CPA license in
the state of Texas.
Gregory M. Robbins has served as our general
partners Treasurer since June 2011. From October 2010 to
April 2011, Mr. Robbins served as Vice President and
Controller of Quality Electric Steel Castings, LP.
155
Prior to that, he was a Vice President with Guggenheim Partners,
LLC from 2006 to 2010. Mr. Robbins worked for Wells Fargo
Energy Capital, LLC from 2004 to 2006 and Comerica Bank, Inc.
from 2002 to 2004. Mr. Robbins holds a B.B.A. in finance
from Southwest Texas State University and a M.S in Finance from
Texas A&M University.
Kenneth A. Hersh has served as a member of the
board of directors of our general partner since its formation in
April 2011. Mr. Hersh is the Chief Executive Officer of NGP
Energy Capital Management and a managing partner of NGP and has
served in those or similar capacities since 1989. He currently
serves as a director of NGP Capital Resources Company, a
business development company that focuses on the energy
industry, and Resolute Energy Corporation. Mr. Hersh served
as a director of Eagle Rock Energy G&P, LLC., the indirect
general partner of Eagle Rock Energy Partners, L.P., a
(i) natural gas gathering, processing and transportation
company and (ii) developer of oil and natural gas
properties from March 2006 until June 2011 and Energy Transfer
Partners, L.L.C., the indirect general partner of Energy
Transfer Partners, L.P., a natural gas gathering and processing
and transportation and storage and retail propane company, from
February 2004 through December 2009, and served as a director of
LE GP, LLC, the general partner of Energy Transfer Equity, L.P.,
from October 2002 through December 2009. Mr. Hersh received
a B.A. in Politics, magna cum laude, in 1985 from Princeton
University. In 1989, he received his M.B.A. from Stanford
University where he graduated as an Arjay Miller Scholar.
Mr. Hersh currently serves on the Deans Council of
the Harvard Kennedy School and on the Advisory Councils of the
Graduate School of Business at Stanford University and The
Bendheim Center for Finance at Princeton University. He is also
a member of the World Economic Forum where he has been a
featured speaker at its annual meeting held in Davos,
Switzerland.
The board believes that Mr. Hersh brings extensive
knowledge to the board and us through his experiences in the
energy industry as an investor, involvement in complex
energy-related transactions and his position as Chief Executive
Officer of NGP Energy Capital Management and co-manager of
NGPs investment portfolio. Mr. Hersh also brings a
wealth of industry-specific transactional skills,
entrepreneurial ideas and a personal network of public and
private capital sources that the board believes will bring us
opportunities that we may not otherwise have.
Reimbursement
of Expenses of Our General Partner
Our partnership agreement requires us to reimburse our general
partner for all direct and indirect expenses it incurs or
payments it makes on our behalf and all other expenses allocable
to us or otherwise incurred by our general partner in connection
with operating our business. Our partnership agreement does not
set a limit on the amount of expenses for which our general
partner and its affiliates, including Memorial Resource, may be
reimbursed.
Upon the closing of this offering, we will enter into an omnibus
agreement with Memorial Resource pursuant to which management,
administrative and operational services will be provided to our
general partner and us to manage and operate our business. Our
general partner will reimburse Memorial Resource, on a monthly
basis, for the allocable expenses it incurs in its performance
under the omnibus agreement, and we will reimburse our general
partner for such payments it makes to Memorial Resource. These
expenses include, among other things, salary, bonus, incentive
compensation and other amounts paid to persons who perform
services for us or on our behalf and other expenses allocated to
our general partner. We expect the expenses to be no more than
those we would be required to pay if we received services from
an unaffiliated third party. Memorial Resource will have
substantial discretion to determine in good faith which expenses
to incur on our behalf and what portion of its expenses to
allocate to us. In turn, our partnership agreement provides that
our general partner will determine in good faith the expenses
that are allocable to us. Please read Certain
Relationships and Related Transactions Agreements
Governing the Transactions Omnibus Agreement.
Executive
Compensation
We and our general partner were formed in April 2011. As such,
our general partner did not accrue any obligations with respect
to executive compensation for its directors and executive
officers for the fiscal year ended December 31, 2010, or
for any prior periods. Accordingly, we are not presenting any
compensation for
156
historical periods. We have not paid or accrued any amounts for
executive compensation for the 2010 fiscal year.
The executive officers of our general partner are employed by
Memorial Resource and will manage the
day-to-day
affairs of our business. The executive officers intend to devote
as much time to the management of our business as is necessary
for the proper conduct of our business and affairs. The amount
of time that each of our executive officers devotes to our
business will be subject to change depending on our activities,
the activities of Memorial Resource, and any acquisitions or
dispositions made by us or Memorial Resource. Because the
executive officers of our general partner are employees of
Memorial Resource, compensation other than the long-term
incentive plan benefits described below, will be determined and
paid by Memorial Resource, and reimbursed by us to the extent
determined by our general partner. The executive officers of our
general partner, as well as the employees of Memorial Resource
who provide services to us, may participate in employee benefit
plans and arrangements sponsored by Memorial Resource, including
plans that may be established in the future. Neither Memorial
Resource nor our general partner has entered into any employment
agreements with any of our executive officers.
We anticipate that, in connection with the closing of this
offering, the board of directors of our general partner will
grant awards to Memorial Resource employees (including the
executive officers of our general partner) that are key to our
operations, as well as our general partners outside
directors, pursuant to our long-term incentive plan described
below; however, the board has not yet made any determination as
to the number of awards, the type of awards or when the awards
would be granted. We anticipate that the vesting of equity
awards to the officers of our general partner will be tied to
time and performance thresholds. We expect that annual bonuses
will be determined based on financial and individual performance.
Compensation
Committee Interlocks and Insider Participation
As a limited partnership, we are not required by NASDAQ to
establish a compensation committee. Although the board of
directors of our general partner does not currently intend to
establish a compensation committee, it may do so in the future.
Compensation
Discussion and Analysis
General
All of our general partners executive officers and other
personnel necessary for our business to function will be
employed and compensated by our general partner or Memorial
Resource, in each case subject to reimbursement by us. We and
our general partner were formed in April 2011; therefore, we
incurred no cost or liability with respect to compensation of
executive officers, nor has our general partner accrued any
liabilities for incentive or retirement benefits for executive
officers for the fiscal year ended December 31, 2010 or for
any prior periods.
Memorial Resource will manage our operations and activities, and
will make certain compensation decisions on our behalf, under
the omnibus agreement. The compensation for all of our executive
officers will be paid by Memorial Resource and we will reimburse
Memorial Resource for costs and expenses incurred for our
benefit or on our behalf pursuant to the terms of the omnibus
agreement. For a detailed description of the reimbursement
arrangements among us, our general partner, and Memorial
Resource relating to the executive officers and employees of our
general partner and the employees of Memorial Resource who
provide services to us, please read Certain Relationships
and Related Party Transactions Agreements Governing
the Transactions Omnibus Agreement.
Responsibility and authority for compensation-related decisions
for executive officers and other personnel employed by our
general partner will reside with our general partner.
Responsibility and authority for compensation-related decisions
for executive officers and other personnel that are employed by
Memorial Resource will reside with Memorial Resource. Our
general partners executive officers will manage our
business as part of the service provided by Memorial Resource
under the omnibus agreement, and the compensation for all of our
executive officers will be indirectly paid by our general
partner through
157
reimbursements to Memorial Resource. All determinations with
respect to awards to be made under our long-term incentive plan
to executive officers and other employees of our general partner
and of Memorial Resource will be made by the board of directors
of our general partner, following the recommendation of Memorial
Resource.
Each of our named executive officers is also an executive
officer of Memorial Resource and we expect that our named
executive officers will devote a significant portion of their
total business time to Memorial Resource and its operations.
Compensation paid or awarded by us with respect to our named
executive officers will reflect only the portion of Memorial
Resources compensation expense allocated to us by Memorial
Resource under the omnibus agreement. Memorial Resource has the
ultimate decision-making authority with respect to the total
compensation of its employees, including our named executive
officers, and (subject to the terms of the omnibus agreement)
with respect to the portion of that compensation that is
allocated to us. Any such compensation decision will not be
subject to any approval by the board of directors of our general
partner.
Memorial Resource intends that the future compensation of our
executive and non-executive officers will include a significant
component of incentive compensation based on our performance and
it expects to employ a compensation philosophy that will
emphasize
pay-for-performance
(primarily, insofar as it relates to our partnership, the
ability to increase sustainable quarterly distributions to
unitholders) based on a combination of our partnerships
performance and the individuals impact on our
partnerships performance and placing the majority of each
officers compensation at risk. We believe this
pay-for-performance
approach will generally align the interests of executive
officers who provide services to us with that of our
unitholders, and at the same time will enable us to maintain a
lower level of base salary overhead in the event our operating
and financial performance fails to meet expectations. Memorial
Resource intends to design our executive compensation to attract
and retain individuals with the background and skills necessary
to successfully execute our business model in a demanding
environment, to motivate those individuals to reach near-term
and long-term goals in a way that aligns their interest with
that of our unitholders, and to reward success in reaching such
goals.
We expect that three primary elements of compensation will be
used to fulfill that design base salary, cash bonus
and long-term equity incentive awards. Cash bonuses and equity
incentives (as opposed to base salary) represent the performance
driven elements of the compensation program. They are also
flexible in application and can be tailored to meet our
objectives. The determination of specific individuals cash
bonuses will reflect their relative contribution to achieving or
exceeding annual goals, and the determination of specific
individuals long-term incentive awards will be based on
their expected contribution in respect of longer term
performance objectives.
We anticipate that, in connection with the closing of this
offering, the board of directors of our general partner will
grant awards to employees of Memorial Resource that are key to
our operations pursuant to our long-term incentive plan
described below; however, the board has not yet made any
determination as to the number of awards, the type of awards or
when the awards would be granted. We anticipate that the vesting
of equity awards to the officers of our general partner will be
tied to time and performance thresholds. We expect that annual
bonuses will be determined based on financial and individual
performance. However, incentive compensation in respect of
services provided to us will not be tied in any material way to
the performance of entities other than our partnership and its
subsidiaries. Specifically, any performance metrics will not be
tied to the performance of Memorial Resource, the Funds or any
other NGP affiliate.
Although we will bear an allocated portion of the costs of
compensation and benefits provided to the Memorial Resource
employees who serve as the executive officers of our general
partner, we will have no control over such costs and will not
establish or direct the compensation policies or practices of
Memorial Resource. Each of these executive officers will
continue to perform services for our general partner, as well as
Memorial Resource and its affiliates, after the closing of this
offering.
Memorial Resource does not maintain a defined benefit pension
plan for its executive officers, because it believes such plans
primarily reward longevity rather than performance. Memorial
Resource provides a basic benefits package generally to all
employees, which includes a 401(k) plan and health, disability
and life
158
insurance. Memorial Resource employees who provide services to
us under the omnibus agreement will be entitled to the same
basic benefits.
Awards
Under Our Long-Term Incentive Plan
In connection with this offering, the board of directors of our
general partner intends to adopt a long-term incentive plan for
employees, officers, consultants and directors of our general
partner and any of its affiliates, including Memorial Resource,
who perform services for us. The long-term incentive plan will
provided for the grant of restricted units, phantom units, unit
options, unit appreciation rights, distribution equivalent
rights, other unit-based awards and unit awards as described
below.
Director
Compensation
Officers or employees of our general partner or its affiliates,
including Memorial Resource, the Funds, and NGP, who also serve
as directors of our general partner will not receive additional
compensation for their service as a director of our general
partner. Our general partner anticipates that each director who
is not an officer or employee of our general partner or its
affiliates will receive compensation for attending meetings of
the board of directors, as well as committee meetings. The
amount of compensation to be paid to non-employee directors has
not yet been determined.
In addition, non-employee directors will be reimbursed for all
out-of-pocket
expenses in connection with attending meetings of the board of
directors or committees. Each director will be fully indemnified
by us for actions associated with being a director to the
fullest extent permitted under Delaware law.
Long-Term
Incentive Plan
Our general partner intends to adopt the Memorial Production
Partners GP LLC Long-Term Incentive Plan, or our long-term
incentive plan, for employees, officers, consultants and
directors of our general partner and any of its affiliates,
including Memorial Resource, who perform services for us. In
connection with the closing of this offering, as well as
annually thereafter to reward service or performance, the board
of directors of our general partner will grant awards to our
general partners independent directors and its executive
officers and key employees pursuant to our long-term incentive
plan. Memorial Resource will determine the overall amount of all
long-term equity incentive compensation to be granted annually
for its employees (including the officers and employees of our
general partner). The portion of that compensation to be granted
under our long-term incentive plan will be granted by our
general partners board of directors following the
recommendation of Memorial Resource. The description set forth
below is a summary of the material features of our long-term
incentive plan.
Our long-term incentive plan will consist of some or all of the
following components: restricted units, phantom units, unit
options, unit appreciation rights, distribution equivalent
rights, other unit-based awards and unit awards. The purpose of
awards under our long-term incentive plan is to provide
additional incentive compensation to employees providing
services to us, and to align the economic interests of such
employees with the interests of our unitholders. Our long-term
incentive plan will limit the number of units that may be
delivered pursuant to vested awards to common units. Common
units cancelled, forfeited or withheld to satisfy exercise
prices or tax withholding obligations will be available for
delivery pursuant to other awards. The plan will be administered
by the board of directors of our general partner or a committee
thereof, which we refer to as the plan administrator. The plan
administrator may also delegate its duties as appropriate.
The plan administrator may terminate or amend our long-term
incentive plan at any time with respect to any units for which a
grant has not yet been made. The plan administrator also has the
right to alter or amend our long-term incentive plan or any part
of the plan from time to time, including increasing the number
of units that may be granted subject to the requirements of the
exchange upon which the common units are listed at that time.
However, no change in any outstanding grant may be made that
would materially reduce the rights or benefits of the
participant without the consent of the participant. The plan
will expire on the earliest of (i) the date on which all
common units available under the plan for grants have been paid
to participants, (ii) termination of the plan by the plan
administrator or (iii) the date 10 years following its
date of adoption.
159
Restricted
Units
A restricted unit is a common unit that vests over a period of
time, and during that time, is subject to forfeiture. The plan
administrator may make grants of restricted units containing
such terms as it shall determine, including the period over
which restricted units will vest. The plan administrator, in its
discretion, may base its determination upon the achievement of
specified financial or other performance objectives. Restricted
units will be entitled to receive quarterly distributions during
the vesting period.
We intend for the restricted units under the long-term incentive
plan to serve as a means of incentive compensation for
performance and not primarily as an opportunity to participate
in the equity appreciation of our common units. Therefore, it is
expected that plan participants will not pay any consideration
for restricted units they receive, and we will receive no
remuneration for the restricted units.
Phantom
Units
A phantom unit entitles the grantee to receive a common unit
upon the vesting of the phantom unit or, in the discretion of
the plan administrator, cash equivalent to the value of a common
unit. The plan administrator may make grants of phantom units
under the plan containing such terms as the plan administrator
shall determine, including the period over which phantom units
granted will vest. The plan administrator, in its discretion,
may base its determination upon the achievement of specified
financial objectives.
We intend for the issuance of common units upon vesting of the
phantom units under the long-term incentive plan to serve as a
means of incentive compensation for performance and not
primarily as an opportunity to participate in the equity
appreciation of our common units. Therefore, it is expected that
plan participants will not pay any consideration for the common
units they receive, and we will receive no remuneration for the
common units.
Unit
Options
Our long-term incentive plan will permit the grant of options
covering common units. The plan administrator may make grants
containing such terms as the plan administrator shall determine.
Unit options will typically have an exercise price that is not
less than the fair market value of the common units on the date
of grant. In general, unit options granted will become
exercisable over a period determined by the plan administrator.
Unit
Appreciation Rights
Our long-term incentive plan will permit the grant of unit
appreciation rights. A unit appreciation right is an award that,
upon exercise, entitles the participant to receive the excess of
the fair market value of a common unit on the exercise date over
the exercise price established for the unit appreciation right.
Such excess will be paid in cash or common units. The plan
administrator may make grants of unit appreciation rights
containing such terms as the plan administrator shall determine.
Unit appreciation rights will typically have an exercise price
that is not less than the fair market value of the common units
on the date of grant. In general, unit appreciation rights
granted will become exercisable over a period determined by the
plan administrator.
Distribution
Equivalent Rights
The plan administrator may, in its discretion, grant
distribution equivalent rights, or DERs, in tandem with phantom
unit awards or other award under our long-term incentive plan.
DERs entitle the participant to receive cash equal to the amount
of any cash distributions made by us during the period the right
is outstanding. Payment of a DER issued in connection with
another award may be subject to the same vesting terms as the
award to which it relates or different vesting terms, in the
discretion of the plan administrator.
160
Other
Unit-Based Awards
Our long-term incentive plan will permit the grant of other
unit-based awards, which are awards that are based, in whole or
in part, on the value or performance of a common unit. Upon
vesting, the award may be paid in common units, cash or a
combination thereof, as provided in the grant agreement.
Unit
Awards
Our long-term incentive plan will permit the grant of common
units that are not subject to vesting restrictions. Unit awards
may be in lieu of or in addition to other compensation payable
to the individual.
Change
in Control; Termination of Service
Awards under our long-term incentive plan will vest
and/or
become exercisable, as applicable, upon a change in
control of us or our general partner, unless provided
otherwise by the plan administrator. The consequences of the
termination of a grantees employment, consulting
arrangement or membership on the board of directors will be
determined by the plan administrator in the terms of the
relevant award agreement.
Source
of Common Units
Common units to be delivered pursuant to awards under our
long-term incentive plan may be common units acquired by our
general partner in the open market, from any other person,
directly from us or any combination of the foregoing. If we
issue new common units upon the grant, vesting or payment of
awards under our long-term incentive plan, the total number of
common units outstanding will increase, and our general partner
will remit the proceeds it receives from a participant, if any,
upon exercise of an award to us. With respect to any awards
settled in cash, our general partner will be entitled to
reimbursement by us for the amount of the cash settlement.
Relation
of Compensation Policies and Practices to Risk
Management
We anticipate that our compensation policies and practices will
reflect the same philosophy and approach as Memorial
Resources. Accordingly, such policies and practices will
be designed to provide rewards for short-term and long-term
performance, both on an individual basis and at the entity
level. In general, optimal financial and operational
performance, particularly in a competitive business, requires
some degree of risk-taking. Accordingly, the use of compensation
as an incentive for performance can foster the potential for
management and others to take unnecessary or excessive risks to
reach performance thresholds which qualify them for additional
compensation.
From a risk management perspective, our policy will be to
conduct our commercial activities within pre-defined risk
parameters that are closely monitored and are structured in a
manner intended to control and minimize the potential for
unwarranted risk-taking. We also routinely monitor and measure
the execution and performance of our projects and acquisitions
relative to expectations.
We expect our compensation arrangements to contain a number of
design elements that serve to minimize the incentive for taking
unwarranted risk to achieve short-term, unsustainable results.
Those elements include delaying the rewards and subjecting such
rewards to forfeiture for terminations related to violations of
our risk management policies and practices or of our code of
conduct.
In combination with our risk-management practices, we do not
believe that risks arising from our compensation policies and
practices for our employees are reasonably likely to have a
material adverse effect on us.
161
SECURITY
OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of our
common and subordinated units that, upon the consummation of
this offering and the related transactions and assuming the
underwriters do not exercise their option to purchase additional
common units, will be owned by:
|
|
|
|
|
each person who then will beneficially own more than 5% of the
then outstanding common units;
|
|
|
|
each director and director nominee of our general partner;
|
|
|
|
each named executive officer of our general partner; and
|
|
|
|
all directors, director nominees and named executive officers of
our general partner as a group.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
Percentage of
|
|
|
|
Percentage of
|
|
Common and
|
|
|
Common
|
|
Common
|
|
Subordinated
|
|
Subordinated
|
|
Subordinated
|
|
|
Units to be
|
|
Units to be
|
|
Units to be
|
|
Units to be
|
|
Units to be
|
|
|
Beneficially
|
|
Beneficially
|
|
Beneficially
|
|
Beneficially
|
|
Beneficially
|
Name of Beneficial Owner(1)
|
|
Owned(2)
|
|
Owned
|
|
Owned
|
|
Owned
|
|
Owned
|
|
Memorial Resource(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Kenneth A. Hersh(4)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
All named executive officers, directors and director nominees as
a group (five persons)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
|
|
|
(1) |
|
The address for all beneficial owners in this table is 1401
McKinney Street, Suite 1025, Houston, Texas 77010. There
are no options, warrants or other rights or obligations
outstanding that are currently exercisable or exercisable within
60 days into common or subordinated units. |
|
(2) |
|
Does not include any common units that may be purchased in a
directed unit program. |
|
(3) |
|
Memorial Resource is owned by Natural Gas Partners VIII, L.P.
(NGP VIII) and Natural Gas Partners IX, L.P.
(NGP IX), which also collectively directly own,
through non-voting membership interests in our general partner,
50% of the economic interest in our incentive distribution
rights. NGP VIII and NGP IX may be deemed to share voting and
dispositive power over the reported securities; thus, each may
also be deemed to be the beneficial owner of these securities.
Each of NGP VIII and NGP IX disclaims beneficial ownership of
the reported securities in excess of such entitys
respective pecuniary interest in the securities. |
|
(4) |
|
G.F.W. Energy VIII, L.P., GFW VIII, L.L.C., G.F.W. Energy IX,
L.P. and GFW IX, L.L.C. may be deemed to beneficially own the
units held by Memorial Resource that are attributable to NGP
VIII and NGP IX by virtue of GFW VIII, L.L.C. being the sole
general partner of G.F.W. Energy VIII, L.P. (which is the
general partner of NGP VIII) and GFW IX, L.L.C. being the
sole general partner of G.F.W. Energy IX, L.P. (which is the
general partner of NGP IX). Kenneth A. Hersh, one of our general
partners directors and who is an Authorized Member of each
of GFW VIII, L.L.C. and GFW IX, L.L.C., may also be deemed to
share the power to vote, or to direct the vote, and to dispose,
or to direct the disposition, of those units. Mr. Hersh
does not own directly any common units or subordinated units. |
Memorial Production Partners GP LLC, our general partner, owns
all of our incentive distribution rights and a 0.1% general
partner interest in us. The following table sets forth the
beneficial ownership of equity interests in our general partner.
|
|
|
|
|
|
|
|
|
|
|
Class A
|
|
Class B
|
|
|
Member
|
|
Member
|
Name of Beneficial Owner
|
|
Interest(a)
|
|
Interest(a)
|
|
Memorial Resource(b)
|
|
|
100
|
%
|
|
|
|
|
Natural Gas Partners VIII, L.P.(c)(d)
|
|
|
|
|
|
|
|
%
|
Natural Gas Partners IX, L.P.(c)(d)
|
|
|
|
|
|
|
|
%
|
162
|
|
|
(a) |
|
Our general partner has two classes of member interests.
Memorial Resource owns the voting Class A member interest,
and will be entitled to 50% of any cash distributions made or
common units issued to our general partner with respect to our
general partners 0.1% general partner interest in us. NGP
VIII and NGP IX
own % and
%, respectively, of the non-voting Class B member interest
in our general partner, which entitles them to an aggregate 50%
of any cash distributions made or common units issued to our
general partner. |
|
(b) |
|
Our general partner is controlled by Memorial Resource, which is
controlled by NGP VIII and NGP IX. Mr. Hersh will share in
distributions made by us with respect to interests held by our
general partner in proportion to his pecuniary interests.
Mr. Hersh disclaims beneficial ownership of the reported
securities in excess of his pecuniary interest in such
securities. In addition, our general partners other
non-independent directors and certain of our general
partners executive officers have indirect financial
interests in Memorial Resource and its affiliates. |
|
(c) |
|
NGP VIII and NGP IX may be deemed to share voting and
dispositive power over the reported interests of Memorial
Resource; thus, each of NGP VIII and NGP IX may also be deemed
to be the beneficial owner of these interests. Each of NGP VIII
and NGP IX disclaims beneficial ownership of such reported
interests in excess of such entitys respective pecuniary
interest in such interests. G.F.W. Energy VIII, L.P., GFW VIII,
L.L.C., G.F.W. Energy IX, L.P. and GFW IX, L.L.C. may be deemed
to beneficially own the interests owned by Memorial Resource
attributable to NGP VIII and NGP IX and the interests held by
NGP VIII and NGP IX by virtue of GFW VIII, L.L.C. being the sole
general partner of G.F.W. Energy VIII, L.P. (which is the
general partner of NGP VIII) and GFW IX, L.L.C. being the
sole general partner of G.F.W. Energy IX, L.P. (which is the
general partner of NGP IX). Kenneth A. Hersh, one of our general
partners directors and who is an Authorized Member of each
of GFW VIII, L.L.C. and GFW IX, L.L.C., may also be deemed to
share the power to vote, or to direct the vote, and to dispose,
or to direct the disposition, of the interests held by NGP VII
and NGP IX. Mr. Hersh does not own directly any interests
in our general partner. |
|
(d) |
|
The address for NGP VIII and NGP IX is 125 E. John
Carpenter Fwy., Suite 600, Irving, Texas 75602. |
163
CERTAIN
RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Upon the consummation of this offering, assuming the
underwriters do not exercise their option to purchase additional
common units, Memorial Resource will control our general partner
and own approximately % of our
outstanding common units and all of our subordinated units.
Memorial Resource owns 100% of the voting membership interests
in our general partner, and the Funds own non-voting membership
interests in our general partner that entitle them collectively
to 50% of all cash distributions and common units received by
our general partner in respect of our incentive distribution
rights. Our general partner will own a 0.1% general partner
interest in us, evidenced
by
general partner units, and all of our incentive distribution
rights. These percentages do not reflect any common units that
may be issued under the long-term incentive plan that our
general partner expects to adopt prior to the closing of this
offering.
Distributions
and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to
be made by us to our general partner and its affiliates in
connection with our formation, ongoing operation and
liquidation. These distributions and payments were determined by
and among affiliated entities and, consequently, were not the
result of arms-length negotiations.
Formation
Stage
|
|
|
The consideration received by our |
|
common
units;
|
general partner and Memorial Resource |
|
subordinated
units;
|
prior to or in connection with this offering |
|
general
partner units
(or general
partner units if the underwriters exercise their option to
purchase additional common units in full);
|
|
|
|
all of our incentive distribution rights; and
|
|
|
|
approximately
$ million in cash.
|
Operational
Stage
|
|
|
Distributions of available cash to our general partner and its
affiliates |
|
We will generally make cash distributions 99.9% to our
unitholders, including Memorial Resource as the holder of
approximately % of our limited
partner interests, pro rata and 0.1% to our general partner,
assuming it makes any capital contributions necessary to
maintain its 0.1% general partner interest in us. In addition,
if distributions exceed the minimum quarterly distribution and
other higher target distribution levels, our general partner
will be entitled to increasing percentages of the distributions,
up to a maximum of 25.0% of the distributions above the highest
target distribution level, including the general partners
0.1% general partner interest. |
|
|
|
Assuming we have sufficient available cash to pay the full
minimum quarterly distribution on all of our outstanding units
for four quarters, our general partner would receive an annual
distribution of approximately
$ million on its general
partner units and Memorial Resource would receive an annual
distribution of approximately
$ million on its common units
and subordinated units. |
|
Payments to our general partner and its affiliates |
|
Our general partner will not receive a management fee or other
compensation for its management of our partnership, but we will
reimburse our general partner for all direct and indirect
expenses it incurs or payments it makes on our behalf and all
other expenses |
164
|
|
|
|
|
allocable to us or otherwise incurred by our general partner and
its affiliates in connection with operating our business. Our
partnership agreement does not set a limit on the amount of
expenses for which our general partner may be reimbursed. These
expenses include salary, bonus, incentive compensation and other
amounts paid to persons who perform services for us or on our
behalf and expenses allocated to our general partner by its
affiliates. Our partnership agreement provides that our general
partner will determine in good faith the amount of such expenses
that are allocable to us. |
|
Withdrawal or removal of our general partner |
|
If our general partner is removed under circumstances where
cause exists or withdraws where that withdrawal violates our
partnership agreement, a successor general partner will have the
option to purchase the departing general partners general
partner interest in us and the incentive distribution rights for
a cash payment equal to the fair market value of those
interests. Under all other circumstances where our general
partner withdraws or is removed by the limited partners, the
departing general partner will have the option to require the
successor general partner to purchase the departing general
partners general partner interest in us and its incentive
distribution rights for their fair market value or to convert
such interests into common units. |
Liquidation
Stage
|
|
|
Liquidation |
|
Upon our liquidation, the partners, including our general
partner, will be entitled to receive liquidating distributions
according to their respective capital account balances. |
Amended
and Restated Limited Liability Company Agreement of Memorial
Production Partners GP LLC
Memorial Resource expects to amend and restate our general
partners limited liability company agreement prior to the
closing of this offering.
Under our general partners amended and restated limited
liability company agreement, at the closing of this offering,
Memorial Resource will own 100% of the voting membership
interests in our general partner and the Funds will hold
non-voting membership interests in our general partner that will
entitle the Funds to collectively receive 50% of any cash
distributions made to our general partner in respect of our
incentive distribution rights, as well as any common units
issued to our general partner in connection with a reset of the
incentive distribution rights.
Agreements
Governing the Transactions
In connection with the closing of this offering, we, our general
partner and its affiliates will enter into the various documents
and agreements that will effect the transactions described in
Summary Our Partnership Structure and
Formation Transactions, including the contribution of
assets to, and the assumption of liabilities by, us and the
application of the proceeds of this offering. These agreements
have been negotiated among affiliated parties and, consequently,
are not the result of arms-length negotiations. All of the
transaction expenses incurred in connection with these
transactions, including the expenses associated with
transferring assets to us, will be paid from the proceeds of
this offering or from amounts borrowed under our new revolving
credit facility.
165
Omnibus
Agreement
Upon the closing of this offering, we and our general partner
will enter into an omnibus agreement with Memorial Resource that
will address the following matters:
|
|
|
|
|
our obligation to reimburse Memorial Resource for all expenses
incurred by Memorial Resource (or payments made on our behalf)
in conjunction with its provision of general and administrative
services to us, including, but not limited to, our public
company expenses and an allocated portion of the salary and
benefits of the executive officers of our general partner and
other employees of Memorial Resource who perform services for us
or on our behalf;
|
|
|
|
our obligation to reimburse Memorial Resource for insurance
coverage expenses it incurs with respect to our business and
operations and with respect to director and officer liability
coverage for the officers and directors of our general
partner; and
|
|
|
|
our obligation to indemnify Memorial Resource for certain
liabilities.
|
The omnibus agreement provides that we must indemnify Memorial
Resource for any liabilities incurred by Memorial Resource
attributable to the operating and administrative services
provided to us under the agreement, other than liabilities
resulting from Memorial Resources bad faith or willful
misconduct. In addition, Memorial Resource must indemnify us for
any liability we incur as a result of Memorial Resources
bad faith or willful misconduct in providing operating and
administrative services under the omnibus agreement. Memorial
Resource may terminate the omnibus agreement in the event that
it ceases to be our affiliate and may also terminate the omnibus
agreement if we fail to pay amounts due under that agreement in
accordance with its terms. The omnibus agreement may only be
assigned by either party with the other partys consent.
Tax
Sharing Agreement
Prior to the closing of this offering, we intend to enter into a
tax sharing agreement pursuant to which we will reimburse
Memorial Resource for our share of state and local income and
other taxes borne by Memorial Resource as a result of our
results being included in a combined or consolidated tax return
filed by Memorial Resource or its affiliates with respect to
periods after the closing of this offering. Memorial Resource
may use its tax attributes to cause its combined or consolidated
group, of which we may be a member for this purpose, to owe no
tax. However, we would nevertheless reimburse Memorial Resource
for the tax we would have owed had the attributes not been
available or used for our benefit, even though Memorial Resource
had no cash expense for that period.
Purchase
and Sale and Contribution Agreements
In connection with the closing of this offering, we intend to
enter into purchase and sale and contribution agreements with
Memorial Resource and certain of its subsidiaries that will
effect, among other things, portions of the formation
transactions, including the transfer of the Partnership
Properties to us. We will hold title to these assets and will
enter into an omnibus agreement with Memorial Resource related
to these assets as discussed above. In addition, under the
purchase and sale and contribution agreements we will agree to
indemnify Memorial Resource and certain of its subsidiaries, as
applicable, against certain environmental claims, losses and
expenses associated with the operation of our assets.
Review,
Approval or Ratification of Transactions with Related
Persons
We expect that we will adopt a Code of Business Conduct and
Ethics that will set forth our policies for the review, approval
and ratification of transactions with related persons. Upon our
adoption of a Code of Business Conduct and Ethics, a director
would be expected to bring to the attention of the Chief
Executive Officer or the board of directors of our general
partner any conflict or potential conflict of interest that may
arise between the director or any affiliate of the director, on
the one hand, and us or our general partner on the other. The
resolution of any such conflict or potential conflict will be
addressed in accordance with Memorial Resources and our
general partners organizational documents and the
provisions of our partnership
166
agreement. The resolution may be determined by disinterested
directors, our general partners board of directors, or the
conflicts committee of our general partners board of
directors.
Upon our adoption of a Code of Business Conduct and Ethics, any
executive officer of our general partner will be required to
avoid conflicts of interest unless approved by the board of
directors.
The board of directors of our general partner will have a
conflicts committee comprised of at least one independent
director. Our general partner may, but is not required to, seek
the approval of the conflicts committee in connection with
future acquisitions from (or other transactions with) Memorial
Resource or any of its affiliates. In the case of any sale of
equity or debt by us to Memorial Resource or any of its
affiliates, we anticipate that our practice will be to obtain
the approval of the conflicts committee for the transaction. The
conflicts committee will be entitled to hire its own financial
and legal advisors in connection with any matters on which the
board of directors of our general partner has sought the
conflicts committees approval.
Memorial Resource and its affiliates will be free to offer
properties to us on terms it deems acceptable, and the board of
directors of our general partner (or the conflicts committee)
will be free to accept or reject any such offers, negotiating
terms it deems acceptable to us. As a result, the board of
directors of our general partner (or the conflicts committee)
will decide, in its sole discretion, the appropriate value of
any assets offered to us by Memorial Resource or its affiliates.
In so doing, we expect the board of directors (or the conflicts
committee) will consider a number of factors in its
determination of value, including, without limitation,
production and reserve data, operating cost structure, current
and projected cash flows, financing costs, the anticipated
impact on distributions to our unitholders, production decline
profile, commodity price outlook, reserve life, future drilling
inventory and the weighting of the expected production between
oil and natural gas.
We expect that Memorial Resource and its affiliates will
consider a number of the same factors considered by the board of
directors of our general partner to determine the proposed price
for any assets it or they may offer to us in future periods. In
addition to these factors, given that Memorial Resource will be
our largest unitholder following the consummation of this
offering and through its and the Funds interest in our
incentive distribution rights, it and they may consider the
potential positive impact on their underlying investment in us
by offering properties to us at attractive purchase prices.
Likewise, it and they may consider the potential negative impact
on their underlying investment in us if we are unable to acquire
additional assets on favorable terms, including the negotiated
purchase price.
167
CONFLICTS
OF INTEREST AND FIDUCIARY DUTIES
Conflicts
of Interest
Conflicts of interest exist and may arise in the future as a
result of the relationships between our general partner and its
affiliates (including Memorial Resource, the Funds, and NGP) on
the one hand, and us and our limited partners, on the other
hand. The directors and officers of our general partner have
fiduciary duties to manage our general partner in a manner
beneficial to its owners. In addition, many of the directors and
officers of our general partner serve in similar capacities with
Memorial Resource and the Funds and their respective affiliates,
and certain of our executive officers and directors will
continue to have economic interests, investments and other
economic incentives in entities affiliated with the Funds, which
may lead to additional conflicts of interest. At the same time,
our general partner has a fiduciary duty to manage our
partnership in a manner beneficial to us and our unitholders.
Whenever a conflict arises between our general partner or its
affiliates, on the one hand, and us and our limited partners, on
the other hand, our general partner will resolve that conflict.
Our partnership agreement contains provisions that modify and
limit our general partners fiduciary duties to our
unitholders. Our partnership agreement also restricts the
remedies available to unitholders for actions taken that,
without those limitations, might constitute breaches of
fiduciary duty.
Our general partner will not be in breach of its obligations
under our partnership agreement or its duties to us or our
unitholders if the resolution of the conflict is:
|
|
|
|
|
approved by the conflicts committee, although our general
partner is not obligated to seek such approval;
|
|
|
|
approved by the vote of a majority of the outstanding common
units, excluding any common units owned by our general partner
or any of its affiliates;
|
|
|
|
on terms no less favorable to us than those generally being
provided to or available from unrelated third parties; or
|
|
|
|
fair and reasonable to us, taking into account the totality of
the relationships among the parties involved, including other
transactions that may be particularly favorable or advantageous
to us.
|
As required by our partnership agreement, the board of directors
of our general partner will maintain a conflicts committee
comprised of at least one independent director. We intend that,
within a year after the closing of this offering, the conflicts
committee will consist of at least two independent directors.
Our general partner may, but is not required to, seek approval
from the conflicts committee of a resolution of a conflict of
interest with our general partner or affiliates. If our general
partner seeks approval from the conflicts committee, the
conflicts committee will determine if the resolution of a
conflict of interest with our general partner or its affiliates
is fair and reasonable to us. Any matters approved by the
conflicts committee in good faith will be conclusively deemed to
be fair and reasonable to us, approved by all of our partners
and not a breach by our general partner of any duties it may owe
us or our unitholders. If our general partner does not seek
approval from the conflicts committee and its board of directors
determines that the resolution or course of action taken with
respect to the conflict of interest satisfies either of the
standards set forth in the third or fourth bullet points above,
then it will be presumed that, in making its decision, the board
of directors acted in good faith, and in any proceeding brought
by or on behalf of any limited partner or us, the person
bringing or prosecuting such proceeding will have the burden of
overcoming such presumption. Unless the resolution of a conflict
is specifically provided for in our partnership agreement, our
general partner or the conflicts committee may consider any
factors it determines in good faith to consider when resolving a
conflict. When our partnership agreement requires someone to act
in good faith, it requires that person to believe that he or she
is acting in our best interest.
Conflicts of interest could arise in the situations described
below, among others:
168
Memorial
Resource, the Funds and other affiliates of our general partner
will not be limited in their ability to compete with us, which
could cause conflicts of interest and limit our ability to
acquire additional assets or businesses.
Our partnership agreement provides that Memorial Resource and
the Funds and their respective affiliates (including NGP and its
affiliates portfolio investments) are not restricted from
owning assets or engaging in businesses that compete directly or
indirectly with us. In addition, Memorial Resource and the Funds
and their respective affiliates may acquire, develop or dispose
of additional oil and natural gas properties or other assets in
the future, without any obligation to offer us the opportunity
to purchase or develop any of those assets.
Because Memorial Resource controls our general partner and also
is permitted to compete with us, Memorial Resource could choose
to acquire properties and pursue opportunities that would have
been suitable for our partnership. In such a case, Memorial
Resource would have the benefit of any such opportunity instead
of us.
NGP and its affiliates (including the Funds) are established
participants in the oil and natural gas industry, and have
resources greater than ours, which factors may make it more
difficult for us to compete with them with respect to commercial
activities as well as for potential acquisitions. As a result,
competition from these affiliates could adversely impact our
results of operations and cash available for distribution to our
unitholders.
Neither
our partnership agreement nor any other agreement requires
Memorial Resource, the Funds or NGP to pursue a business
strategy that favors us. The directors and officers of Memorial
Resource, the Funds and their respective affiliates (including
NGP) have a fiduciary duty to make decisions in the best
interests of their respective equity holders, which may be
contrary to our interests.
Because the officers and certain of the directors of our general
partner are also officers
and/or
directors of Memorial Resource, the Funds and their respective
affiliates, such officers and directors have fiduciary duties to
Memorial Resource, the Funds and their respective affiliates
that may cause them to pursue business strategies that
disproportionately benefit Memorial Resource, the Funds and
their respective affiliates or which otherwise are not in our
best interests.
Pursuant to the terms of our partnership agreement, the doctrine
of corporate opportunity, or any analogous doctrine, shall not
apply to our general partner or any of its affiliates, including
its officers, directors, Memorial Resource, the Funds or any of
their affiliates. Any such person or entity that becomes aware
of a potential transaction, agreement, arrangement or other
matter that may be an opportunity for us will not have any duty
to communicate or offer such opportunity to us. Any such person
or entity will not be liable to us or to any limited partner for
breach of any fiduciary for itself, directs such opportunity to
another person or entity or does not communicate such
opportunity or information to us. Therefore, Memorial Resource,
the Funds and their affiliates may compete with us for
investment opportunities.
Our
general partner is allowed to take into account the interests of
parties other than us in resolving conflicts of
interest.
Our partnership agreement contains provisions that reduce the
standards to which our general partner would otherwise be held
by state fiduciary duty law. For example, our partnership
agreement permits our general partner to make a number of
decisions in its individual capacity, as opposed to in its
capacity as our general partner. This entitles our general
partner to consider only the interests and factors that it
desires, and it has no duty or obligation to give any
consideration to any interest of, or factors affecting, us, our
affiliates or any limited partner. Examples include our general
partners limited call right, its registration rights, its
determination whether or not to consent to any merger or
consolidation involving us, and its decision to convert its
incentive distribution rights into common units.
Many
of the directors and all of the officers who have responsibility
for our management have significant duties with, and will spend
significant time serving, entities that compete with us in
seeking acquisitions
169
and business opportunities and, accordingly, may have
conflicts of interest in allocating time or pursuing business
opportunities.
All of the officers of our general partner hold similar
positions with Memorial Resource, and many of the directors of
our general partner, who are responsible for managing our
general partners direction of our operations and
acquisition activities, hold positions of responsibility with
other entities (including NGP) that are in the business of
identifying and acquiring oil and natural gas properties. For
example, the Funds and their affiliates (including NGP) are in
the business of investing in oil and natural gas companies with
independent management teams that also seek to acquire oil and
natural gas properties, and Memorial Resource is in the business
of acquiring and developing oil and natural gas properties.
Mr. Hersh, a director of our general partner, is the Chief
Executive Officer of NGP Energy Capital Management and a
managing partner of NGP; and Mr. Weinzierl, the President,
Chief Executive Officer and Chairman of the board of directors
of our general partner, was a managing director of NGP prior to
assuming his current positions with Memorial Resource and our
general partner and continues to hold ownership interests in the
Funds and certain of their affiliates. After the closing of this
offering, officers of our general partner will continue to
devote significant time to the business of Memorial Resource. We
cannot assure you that any conflicts that may arise between us
and our unitholders, on the one hand, and Memorial Resource or
the Funds, on the other hand, will be resolved in our favor. The
existing positions held by these directors and officers may give
rise to fiduciary duties that are in conflict with the fiduciary
duties they owe to us. These officers and directors may become
aware of business opportunities that may be appropriate for
presentation to us as well as to the other entities with which
they are or may become affiliated. Due to these existing and
potential future affiliations, they may present potential
business opportunities to other entities prior to presenting
them to us, which could cause additional conflicts of interest.
They may also decide that certain opportunities are more
appropriate for other entities with which they are affiliated,
and as a result, they may elect not to present them to us. For
additional discussion of our managements business
affiliations and the potential conflicts of interest of which
our unitholders should be aware, please read Business and
Properties Our Principal Business
Relationships.
Neither
we nor our general partner have any employees and we will rely
solely on the employees of Memorial Resource to manage our
business. The management team of Memorial Resource, which
includes the individuals who will manage us, will also perform
substantially similar services for itself and will own and
operate its own assets, and thus will not be solely focused on
our business.
Neither we nor our general partner have any employees and we
will rely solely on Memorial Resource to operate our assets.
Upon consummation of this offering, our general partner will
enter into a omnibus agreement with Memorial Resource, pursuant
to which, among other things, Memorial Resource has agreed to
make available to our general partner Memorial Resources
personnel in a manner that will allow us to carry on our
business in the same manner in which it was carried on by our
predecessor.
Memorial Resource will provide substantially similar services
with respect to its own assets and operations. Because Memorial
Resource will be providing services to us that are substantially
similar to those provided to itself, Memorial Resource may not
have sufficient human, technical and other resources to provide
those services at a level that Memorial Resource would be able
to provide to us if it were solely focused on our business and
operations. Memorial Resource may make internal decisions on how
to allocate its available resources and expertise that may not
always be in our best interest compared to Memorial
Resources interests. There is no requirement that Memorial
Resource favor us over itself in providing its services. If the
employees of Memorial Resource and their affiliates do not
devote sufficient attention to the management and operation of
our business, our financial results may suffer and our ability
to make distributions to our unitholders may be reduced.
170
Our
partnership agreement limits our general partners
fiduciary duties to holders of our units and restricts the
remedies available to unitholders for actions taken by our
general partner that might otherwise constitute breaches of
fiduciary duty.
Our partnership agreement contains provisions that reduce the
fiduciary standards to which our general partner would otherwise
be held by state fiduciary duty laws. For example, our
partnership agreement:
|
|
|
|
|
permits our general partner to make a number of decisions in its
individual capacity, as opposed to in its capacity as our
general partner. This entitles our general partner to consider
only the interests and factors that it desires, and it has no
duty or obligation to give any consideration to any interest of,
or factors affecting, us, our affiliates or any limited partner.
Examples include the exercise of its right to reset the target
distribution levels of its incentive distribution rights at
higher levels and receive, in connection with this reset, common
units, the exercise of its limited call right, the exercise of
its rights to transfer or vote the units it owns, the exercise
of its registration rights and its determination whether or not
to consent to any merger or consolidation involving us or to any
amendment to the partnership agreement;
|
|
|
|
provides that our general partner will not have any liability to
us or our unitholders for decisions made in its capacity as
general partner so long as it acted in good faith;
|
|
|
|
generally provides that affiliated transactions and resolutions
of conflicts of interest not approved by the conflicts committee
of the board of directors of our general partner acting in good
faith and not involving a vote of unitholders must be on terms
no less favorable to us than those generally being provided to
or available from unrelated third parties or must be fair
and reasonable to us, as determined by our general partner
in good faith. In determining whether a transaction or
resolution is fair and reasonable, our general
partner may consider the totality of the relationships between
the parties involved, including other transactions that may be
particularly advantageous or beneficial to us;
|
|
|
|
provides that our general partner and its officers and directors
will not be liable for monetary damages to us or our limited
partners for any acts or omissions unless there has been a final
and non-appealable judgment entered by a court of competent
jurisdiction determining that our general partner or its
officers and directors acted in bad faith or engaged in fraud or
willful misconduct or, in the case of a criminal matter, acted
with knowledge that the conduct was criminal; and
|
|
|
|
provides that in resolving conflicts of interest, it will be
presumed that in making its decision our general partners
board of directors or the conflicts committee of our general
partners board of directors acted in good faith, and in
any proceeding brought by or on behalf of any limited partner or
us, the person bringing or prosecuting such proceeding will have
the burden of overcoming such presumption.
|
By purchasing a common unit, a unitholder will become bound by
the provisions in the partnership agreement, including the
provisions discussed above.
Except
in limited circumstances, our general partner has the power and
authority to conduct our business without unitholder
approval.
Under our partnership agreement, our general partner has full
power and authority to do all things, other than those items
that require unitholder approval or with respect to which our
general partner has sought conflicts committee approval, on such
terms as it determines to be necessary or appropriate to conduct
our business, including, but not limited to, the following:
|
|
|
|
|
the making of any expenditures, the lending or borrowing of
money, the assumption or guarantee of or other contracting for,
indebtedness and other liabilities, the issuance of evidences of
indebtedness, including indebtedness that is convertible into
our securities, and the incurring of any other obligations;
|
|
|
|
the purchase, sale or other acquisition or disposition of our
securities, or the issuance of additional options, rights,
warrants and unit appreciation rights relating to our securities;
|
171
|
|
|
|
|
the mortgage, pledge, encumbrance, hypothecation or exchange of
any or all of our assets;
|
|
|
|
the negotiation, execution and performance of any contracts,
conveyances or other instruments;
|
|
|
|
the distribution of our cash;
|
|
|
|
the selection and dismissal of employees and agents, outside
attorneys, accountants, consultants and contractors and the
determination of their compensation and other terms of
employment or hiring;
|
|
|
|
the maintenance of insurance for our benefit and the benefit of
our partners;
|
|
|
|
the formation of, or acquisition of an interest in, the
contribution of property to, and the making of loans to, any
limited or general partnerships, joint ventures, corporations,
limited liability companies or other entities;
|
|
|
|
the control of any matters affecting our rights and obligations,
including the bringing and defending of actions at law or in
equity and otherwise engaging in the conduct of litigation,
arbitration or mediation and the incurring of legal expense and
the settlement of claims and litigation;
|
|
|
|
the indemnification of any person against liabilities and
contingencies to the extent permitted by law;
|
|
|
|
the making of tax, regulatory and other filings or rendering of
periodic or other reports to governmental or other agencies
having jurisdiction over our business or assets; and
|
|
|
|
the entering into of agreements with any of its affiliates to
render services to us or to itself in the discharge of its
duties as our general partner.
|
Our partnership agreement provides that our general partner must
act in good faith when making decisions on our
behalf, and our partnership agreement further provides that in
order for a determination by our general partner to be made in
good faith, our general partner must believe that
the determination is in our best interests. Please read
The Partnership Agreement Limited Voting
Rights for information regarding matters that require
unitholder approval.
Our
general partner determines the amount and timing of asset
purchases and sales, capital expenditures, borrowings, issuance
of additional partnership interests and the creation, reduction
or increase of reserves, each of which can affect the amount of
cash that is distributed to our unitholders.
The amount of cash that is available for distribution to
unitholders is affected by decisions of our general partner
regarding such matters as:
|
|
|
|
|
the manner in which our business is operated;
|
|
|
|
the amount, nature and timing of asset purchases and sales;
|
|
|
|
the amount, nature and timing of our capital expenditures;
|
|
|
|
the amount of borrowings;
|
|
|
|
the issuance of additional units; and
|
|
|
|
the creation, reduction or increase of reserves in any quarter.
|
Our general partner determines the amount and timing of any
capital expenditures and whether a capital expenditure is
classified as a maintenance capital expenditure, which reduces
operating surplus, or a growth capital expenditure, which does
not reduce operating surplus. This determination can affect the
amount of cash that is distributed to our unitholders and to our
general partner and the ability of the subordinated units to
convert into common units.
In addition, our general partner may use an amount, initially
equal to $ million, which
would not otherwise constitute available cash from operating
surplus, in order to permit the payment of cash distributions on
its units and incentive distribution rights. All of these
actions may affect the amount of cash distributed to
172
our unitholders and our general partner and may facilitate the
conversion of subordinated units into common units. Please read
Provisions of Our Partnership Agreement Relating to Cash
Distributions.
In addition, borrowings by us and our affiliates do not
constitute a breach of any duty owed by our general partner to
our unitholders, including borrowings that have the purpose or
effect of enabling our general partner or its affiliates to
receive distributions on any subordinated units held by them or
the incentive distribution rights or enabling the expiration of
the subordination period.
For example, if we have not generated sufficient cash from our
operations to pay the minimum quarterly distribution on our
common units and subordinated units, our partnership agreement
permits us to borrow funds, which would enable us to make this
distribution on all outstanding units.
Our partnership agreement provides that we and our subsidiaries
may borrow funds from our general partner and its affiliates.
Our general partner and its affiliates may not borrow funds from
us or our operating subsidiaries.
Our
general partner determines which costs incurred by it are
reimbursable by us.
We will reimburse our general partner and its affiliates for
costs incurred in managing and operating our business, including
costs incurred in rendering staff and support services to us.
Our partnership agreement provides that our general partner will
determine the expenses that are allocable to us in good faith.
Our
partnership agreement does not restrict our general partner from
causing us to pay it or its affiliates for any services rendered
to us or entering into additional contractual arrangements with
any of these entities on our behalf.
Our partnership agreement allows our general partner to
determine, in good faith, any amounts to pay itself or its
affiliates for any services rendered to us. Our general partner
may also enter into additional contractual arrangements with
Memorial Resource, the Funds or their respective affiliates on
our behalf. Similarly, agreements, contracts or arrangements
between us and our general partner, Memorial Resource, the Funds
or their respective affiliates will not be required to be
negotiated on an arms-length basis, although, in some
circumstances, our general partner may determine that the
conflicts committee of our general partner may make a
determination on our behalf with respect to one or more of these
types of situations.
Our general partner will determine, in good faith, the terms of
any of these transactions entered into after the sale of the
common units offered in this offering.
Our general partner and its affiliates will have no obligation
to permit us to use any facilities or assets of our general
partner or its affiliates, except as may be provided in
contracts entered into specifically dealing with that use. There
is no obligation of our general partner or its affiliates to
enter into any contracts of this kind.
Our
general partner may exercise its right to call and purchase
common units if it and its affiliates own more than 80% of the
common units.
Our general partner may exercise its right to call and purchase
common units as provided in the partnership agreement or assign
this right to one of its affiliates or to us. Our general
partner is not bound by fiduciary duty restrictions in
determining whether to exercise this right. As a result, a
common unitholder may have his common units purchased from him
at an undesirable time or price. Please read The
Partnership Agreement Limited Call Right.
Common
unitholders will have no right to enforce obligations of our
general partner and its affiliates under agreements with
us.
Any agreements between us, on the one hand, and our general
partner, Memorial Resource, the Funds and their respective
affiliates, on the other, will not grant to the unitholders,
separate and apart from us, the
173
right to enforce the obligations of our general partner,
Memorial Resource, the Funds and their respective affiliates in
our favor.
Our
general partner and Memorial Resource may be able to amend our
partnership agreement without the approval of any other
unitholder after the subordination period.
Our general partner has the discretion to propose amendments to
our partnership agreement, certain of which may be made by our
general partner without unitholder approval. Our partnership
agreement generally may not be otherwise amended during the
subordination period without the approval of a majority of our
public common unitholders. However, after the subordination
period has ended, our partnership agreement can be amended with
the consent of our general partner and the approval of the
holders of a majority of our outstanding common units (including
common units held by Memorial Resource and its affiliates). Upon
the consummation of this offering, Memorial Resource will own
our general partner and will control the voting of an aggregate
of approximately % of our
outstanding common units and all of our subordinated units.
Assuming that Memorial Resource retains a sufficient number of
its common units and that we do not issue additional common
units, our general partner and Memorial Resource will have the
ability to amend our partnership agreement without the approval
of any other unitholder after the subordination period. Please
read The Partnership Agreement Amendment of
the Partnership Agreement.
Our
general partner intends to limit its liability regarding our
obligations.
Our general partner will enter into contractual arrangements on
our behalf and intends to limit its liability under such
contractual arrangements so that the other party has recourse
only to our assets and not against our general partner or its
assets. The partnership agreement provides that any action taken
by our general partner to limit its liability is not a breach of
our general partners fiduciary duties, even if we could
have obtained more favorable terms without the limitation on
liability.
Contracts
between us, on the one hand, and our general partner and its
affiliates, on the other, will not be the result of
arms-length negotiations.
Our partnership agreement allows our general partner to
determine, in good faith, any amounts to pay itself, Memorial
Resource, the Funds and their respective for any services
rendered to us. Our general partner may also enter into
additional contractual arrangements with Memorial Resource, the
Funds and their respective affiliates on our behalf. Neither the
partnership agreement nor any of the other agreements, contracts
and arrangements between us, on the one hand, and our general
partner, Memorial Resource, the Funds and their respective
affiliates, on the other, are or will be the result of
arms-length negotiations.
Our
general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
The attorneys, independent accountants and others who have
performed services for us regarding this offering have been
retained by our general partner. The attorneys, independent
accountants and others who perform services for us are selected
by our general partner, or the conflicts committee of our
general partners board of directors, and may also perform
services for our general partner and its affiliates. We may
retain separate counsel for ourselves or the holders of common
units in the event of a conflict of interest between our general
partner and its affiliates, on the one hand, and us or the
holders of common units, on the other, depending on the nature
of the conflict. We do not intend to do so in most cases.
Our
general partner may elect to cause us to issue common units to
it in connection with a resetting of the target distribution
levels related to our general partners incentive
distribution rights without the approval of the conflicts
committee of the board of directors of our general partner or
our unitholders. This election may result in lower distributions
to our common unitholders in certain situations.
Our general partner has the right (but not the obligation), at
any time when there are no subordinated units outstanding and it
has received incentive distributions at the highest level to
which it is entitled (25%,
174
assuming it has maintained its 0.1% general partner interest)
for each of the prior four consecutive fiscal quarters, to reset
the initial target distribution levels at higher levels based on
our cash distribution at the time of the exercise of the reset
election. Following any reset election by our general partner,
the minimum quarterly distribution will be reset to an amount
equal to the average cash contribution per common unit for the
two fiscal quarters immediately preceding the reset election
(such amount is referred to as the reset minimum quarterly
distribution) and the target distribution levels will be
reset to correspondingly higher levels based on percentage
increases above the reset minimum quarterly distribution.
We anticipate that our general partner would exercise this reset
right (if at all) to facilitate acquisitions or internal growth
projects that would not be sufficiently accretive to cash
distributions per common unit without such conversion; however,
it is possible that our general partner could exercise this
reset election at a time when we are experiencing declines in
our aggregate cash distributions or at a time when our general
partner expects that we will experience declines in our
aggregate cash distributions in the foreseeable future. In such
situations, our general partner may be experiencing, or may
expect to experience, declines in the cash distributions it
receives related to its incentive distribution rights and may
therefore desire to be issued our common units, which are
entitled to specified priorities with respect to our
distributions and which therefore may be more advantageous for
the general partner to own in lieu of the right to receive
incentive distribution payments based on target distribution
levels that are less certain to be achieved in the then current
business environment. As a result, a reset election may cause
our common unitholders to experience dilution in the amount of
cash distributions that they would have otherwise received had
we not issued new common units to our general partner in
connection with resetting the target distribution levels related
to our general partners incentive distribution rights.
Please read Provisions of Our Partnership Agreement
Relating to Cash Distributions General
Partners Right to Reset Incentive Distribution
Levels.
Fiduciary
Duties
Our general partner is accountable to us and our unitholders as
a fiduciary. Fiduciary duties owed to unitholders by our general
partner are prescribed by law and the partnership agreement. The
Delaware Revised Uniform Limited Partnership Act, which we refer
to in this prospectus as the Delaware Act, provides that
Delaware limited partnerships may, in their partnership
agreements, modify, restrict, eliminate or expand the fiduciary
duties otherwise owed by a general partner to limited partners
and the partnership.
Our partnership agreement contains various provisions modifying
and restricting the fiduciary duties that might otherwise be
owed by our general partner. We have adopted these restrictions
to allow our general partner, Memorial Resource, the Funds and
their respective affiliates to engage in transactions with us
that would otherwise be prohibited by state-law fiduciary duty
standards and to take into account the interests of other
parties in addition to our interests when resolving conflicts of
interest. We believe this is appropriate and necessary because
our general partners board of directors has fiduciary
duties to manage our general partner in a manner beneficial to
its owners, as well as to our unitholders. Without these
modifications, our general partners ability to make
decisions involving conflicts of interest would be restricted.
The modifications to the fiduciary standards enable our general
partner to take into consideration the interests of all parties
involved in the proposed action, so long as the resolution is
fair and reasonable to us. These modifications also enable our
general partner to attract and retain experienced and capable
directors. These modifications are detrimental to our common
unitholders because they restrict the remedies available to
unitholders for actions that, without those limitations, might
constitute breaches of fiduciary duty, as described below, and
permit our general partner to take into account the interests of
third parties in addition to our interests when resolving
conflicts of interest.
175
The following is a summary of the material restrictions of the
fiduciary duties owed by our general partner to the limited
partners:
|
|
|
State-law fiduciary duty standards |
|
Fiduciary duties are generally considered to include an
obligation to act in good faith and with due care and loyalty.
The duty of care, in the absence of a provision in a partnership
agreement providing otherwise, would generally require a general
partner to act for the partnership in the same manner as a
prudent person would act on his own behalf. The duty of loyalty,
in the absence of a provision in a partnership agreement
providing otherwise, would generally prohibit a general partner
of a Delaware limited partnership from taking any action or
engaging in any transaction where a conflict of interest is
present. |
|
Rights and remedies of unitholders |
|
The Delaware Act generally provides that a limited partner may
institute legal action on behalf of the partnership to recover
damages from a third-party where a general partner has refused
to institute the action or where an effort to cause a general
partner to do so is not likely to succeed. In addition, the
statutory or case law of some jurisdictions may permit a limited
partner to institute legal action on behalf of himself and all
other similarly situated limited partners to recover damages
from a general partner for violations of its fiduciary duties to
the limited partners. |
|
Partnership agreement modified standards |
|
Our partnership agreement contains provisions that waive or
consent to conduct by our general partner and its affiliates
that might otherwise raise issues about compliance with
fiduciary duties or applicable law. For example, our partnership
agreement provides that when our general partner is acting in
its capacity as our general partner, as opposed to in its
individual capacity, it must act in good faith and
will not be subject to any other standard under applicable law.
In addition, when our general partner is acting in its
individual capacity, as opposed to in its capacity as our
general partner, it may act without any fiduciary obligation to
us or the unitholders whatsoever. These standards reduce the
obligations to which our general partner would otherwise be held. |
|
|
|
In addition to the other more specific provisions limiting the
obligations of our general partner, our partnership agreement
further provides that our general partner and its officers and
directors will not be liable for monetary damages to us or our
limited partners for errors of judgment or for any acts or
omissions unless there has been a final and non-appealable
judgment by a court of competent jurisdiction determining that
our general partner or its officers and directors acted in bad
faith or engaged in fraud or willful misconduct, or in the case
of a criminal matter, acted with the knowledge that such conduct
was unlawful. |
176
|
|
|
|
|
Special Provisions Regarding Affiliate
Transactions. Our partnership agreement
generally provides that affiliate transactions and resolutions
of conflicts of interest that are not approved by vote of
unitholders and that are not approved by the conflicts committee
of the board of directors of our general partner must be: |
|
|
|
on terms no less favorable to us than those
generally being provided to or available from unrelated third
parties; or
|
|
|
|
fair and reasonable to us, taking into
account the totality of the relationships between the parties
involved (including other transactions that may be particularly
favorable or advantageous to us).
|
|
|
|
If our general partner does not seek approval from the conflicts
committee and the board of directors of our general partner
determines that the resolution or course of action taken with
respect to the conflict of interest satisfies either of the
standards set forth in the bullet points above, then it will be
presumed that, in making its decision, the board of directors,
which may include board members affected by the conflict of
interest, acted in good faith, and in any proceeding brought by
or on behalf of any limited partner or us, the person bringing
or prosecuting such proceeding will have the burden of
overcoming such presumption. These standards reduce the
obligations to which our general partner would otherwise be held. |
By purchasing our common units, each common unitholder
automatically agrees to be bound by the provisions in our
partnership agreement, including the provisions discussed above.
This is in accordance with the policy of the Delaware Act
favoring the principle of freedom of contract and the
enforceability of partnership agreements. The failure of a
limited partner to sign a partnership agreement does not render
our partnership agreement unenforceable against that person.
Under our partnership agreement, we must indemnify our general
partner and its officers, directors, managers and certain other
specified persons, to the fullest extent permitted by law,
against liabilities, costs and expenses incurred by our general
partner or these other persons. We must provide this
indemnification unless there has been a final and non-appealable
judgment by a court of competent jurisdiction determining that
these persons acted in bad faith or engaged in fraud or willful
misconduct. We must also provide this indemnification for
criminal proceedings unless our general partner or these other
persons acted with knowledge that their conduct was unlawful.
Thus, our general partner could be indemnified for its negligent
acts if it meets the requirements set forth above. To the extent
these provisions purport to include indemnification for
liabilities arising under the Securities Act, in the opinion of
the SEC, such indemnification is contrary to public policy and,
therefore, unenforceable. Please read The Partnership
Agreement Indemnification.
177
DESCRIPTION
OF THE COMMON UNITS
The
Units
The common units and the subordinated units are separate classes
of limited partner interests in us. The holders of units are
entitled to participate in partnership distributions and
exercise the rights or privileges available to limited partners
under our partnership agreement. For a description of the
relative rights and preferences of holders of common units and
subordinated units in and to partnership distributions, please
read this section and Our Cash Distribution Policy and
Restrictions on Distributions. For a description of other
rights and privileges of limited partners under our partnership
agreement, including limited voting rights, please read
The Partnership Agreement.
Transfer
Agent and Registrar
Duties
will
serve as registrar and transfer agent for the common units. We
will pay all fees charged by the transfer agent for transfers of
common units, except the following, which must be paid by our
unitholders:
|
|
|
|
|
surety bond premiums to replace lost or stolen certificates or
to cover taxes and other governmental charges;
|
|
|
|
special charges for services requested by a common
unitholder; and
|
|
|
|
other similar fees or charges.
|
There will be no charge to our unitholders for disbursements of
our cash distributions. We will indemnify the transfer agent,
its agents and each of their respective stockholders, directors,
officers and employees against all claims and losses that may
arise out of their actions for their activities in that
capacity, except for any liability due to any gross negligence
or willful misconduct of the indemnitee.
Resignation
or Removal
The transfer agent may resign, by notice to us, or be removed by
us. The resignation or removal of the transfer agent will become
effective upon our appointment of a successor transfer agent and
registrar and its acceptance of the appointment. If no successor
is appointed, our general partner may act as the transfer agent
and registrar until a successor is appointed.
Transfer
of Common Units
By transfer of common units in accordance with our partnership
agreement, each transferee of common units will be admitted as a
limited partner with respect to the common units transferred
when such transfer and admission are reflected in our books and
records. Each transferee:
|
|
|
|
|
represents that the transferee has the capacity, power and
authority to become bound by our partnership agreement;
|
|
|
|
automatically agrees to be bound by the terms and conditions of
our partnership agreement; and
|
|
|
|
gives the consents, waivers and approvals contained in our
partnership agreement, such as the approval of all transactions
and agreements that we are entering into in connection with our
formation and this offering.
|
In addition to other rights acquired upon transfer, the
transferor gives the transferee the right to become a
substituted limited partner in our partnership for the
transferred common units. A transferee will become a substituted
limited partner of our partnership for the transferred common
units automatically upon the
178
recording of the transfer on our books and records. Our general
partner will cause any transfers to be recorded on our books and
records no less frequently than quarterly.
Until a common unit has been transferred on our books, we and
the transfer agent may treat the record holder of the unit as
the absolute owner for all purposes, except as otherwise
required by law or stock exchange regulations.
We may, at our discretion, treat the nominee holder of a common
unit as the absolute owner. In that case, the beneficial
holders rights are limited solely to those that it has
against the nominee holder as a result of any agreement between
the beneficial owner and the nominee holder.
Common units are securities and any transfers are subject to the
laws governing transfers of securities.
179
THE
PARTNERSHIP AGREEMENT
The following is a summary of the material provisions of our
partnership agreement. The form of our partnership agreement is
included in this prospectus as Appendix A. We will provide
prospective investors with a copy of our partnership agreement
upon request at no charge.
We summarize the following provisions of our partnership
agreement elsewhere in this prospectus:
|
|
|
|
|
with regard to distributions of available cash, please read
Our Cash Distribution Policy and Restrictions on
Distributions and Provisions of Our Partnership
Agreement Relating to Cash Distributions;
|
|
|
|
with regard to the fiduciary duties of our general partner,
please read Conflicts of Interest and Fiduciary
Duties;
|
|
|
|
with regard to the transfer of common units, please read
Description of the Common Units Transfer of
Common Units; and
|
|
|
|
with regard to allocations of taxable income, taxable loss and
other matters, please read Material Tax Consequences.
|
Organization
and Duration
Our partnership was organized in April 2011 and will have a
perpetual existence unless terminated pursuant to the terms of
our partnership agreement.
Purpose
Our purpose under our partnership agreement is to engage in any
business activity that is approved by our general partner and
that lawfully may be conducted by a limited partnership
organized under Delaware law. However, our general partner may
not cause us to engage in any business activity that it
determines would cause us to be treated as an association
taxable as a corporation or otherwise taxable as an entity for
federal income tax purposes.
Although our general partner has the ability to cause us and our
subsidiaries to engage in activities other than the ownership,
acquisition, exploitation and development of oil and natural gas
properties and the ownership, acquisition and operation of
related assets, our general partner has no current plans to do
so and may decline to do so free of any fiduciary duty or
obligation whatsoever to us or our limited partners, including
any duty to act in good faith or in the best interests of us or
our limited partners. Our general partner is generally
authorized to perform all acts it determines to be necessary or
appropriate to carry out our purposes and to conduct our
business.
Cash
Distributions
Our partnership agreement specifies the manner in which we will
make cash distributions to holders of our common units and other
partnership securities as well as to our general partner in
respect of its general partner interest. For a description of
these cash distribution provisions, please read Provisions
of Our Partnership Agreement Relating to Cash
Distributions.
Capital
Contributions
Unitholders are not obligated to make additional capital
contributions, except as described below under
Limited Liability. Our general partner
has the right, but not the obligation, to contribute a
proportionate amount of capital to us to maintain its 0.1%
general partner interest in us if we issue additional units. Our
general partners 0.1% interest in us, and the percentage
of our cash distributions to which it is entitled, will be
proportionately reduced if we issue additional units in the
future and our general partner does not contribute a
proportionate amount of capital to us to maintain its 0.1%
general partner interest. To maintain its
180
0.1% general partner interest in us, our general partner will be
entitled to make capital contributions in the form of common
units based on the then-current market value of the contributed
common units.
Limited
Voting Rights
The following is a summary of the unitholder vote required for
each of the matters specified below.
Various matters require the approval of a unit
majority, which means:
|
|
|
|
|
during the subordination period, the approval of a majority of
the outstanding common units, excluding those common units held
by our general partner and its affiliates, and a majority of the
outstanding subordinated units, each voting as a separate
class; and
|
|
|
|
after the subordination period, the approval of a majority of
the outstanding common units.
|
By virtue of the exclusion of those common units held by our
general partner and its affiliates from the required vote, and
by their ownership of all of the subordinated units, during the
subordination period, our general partner and its affiliates do
not have the ability to ensure passage of, but do have the
ability to ensure defeat of, any amendment that requires a unit
majority.
In voting their common units and subordinated units, our general
partner and its affiliates will have no fiduciary duty or
obligation whatsoever to us or the limited partners, including
any duty to act in good faith or in the best interests of us or
the limited partners.
|
|
|
Issuance of additional units |
|
No approval right. Please read Issuance of
Additional Securities. |
|
Amendment of the partnership agreement |
|
Certain amendments may be made by our general partner without
the approval of the unitholders. Other amendments generally
require the approval of a unit majority. Please read
Amendment of the Partnership Agreement. |
|
Merger of our partnership or the sale of all or substantially
all of our assets |
|
Unit majority, in certain circumstances. Please read
Merger, Consolidation, Conversion, Sale or
Other Disposition of Assets. |
|
Dissolution of our partnership |
|
Unit majority. Please read Termination and
Dissolution. |
|
Continuation of our business upon dissolution |
|
Unit majority. Please read Termination and
Dissolution. |
|
Withdrawal of our general partner |
|
Prior
to ,
2021, under most circumstances, the approval of a majority of
the common units, excluding common units held by our general
partner and its affiliates, is required for the withdrawal of
our general partner in a manner that would cause a dissolution
of our partnership. Please read
Withdrawal or Removal of Our General
Partner. |
|
Removal of our general partner |
|
Not less than
662/3%
of the outstanding units, including units held by our general
partner and its affiliates. Please read
Withdrawal or Removal of Our General
Partner. |
|
Transfer of our general partner interest |
|
Our general partner may transfer without a vote of our
unitholders all, but not less than all, of its general partner
interest in us to an affiliate or another person (other than an
individual) in connection with its merger or consolidation with
or into, or sale of all, or substantially all, of its assets, to
such person. The approval of a majority of the common units,
excluding common units held by our general partner and its
affiliates, is required in other circumstances for a transfer of
the general partner interest to a |
181
|
|
|
|
|
third-party prior
to ,
2021. Please read Transfer of General Partner
Units. |
|
Transfer of incentive distribution rights |
|
No approval rights. Please read Transfer of
Incentive Distribution Rights. |
|
Transfer of ownership interests in our general partner |
|
No approval required. Please read Transfer of
Ownership Interests in Our General Partner. |
Applicable
Law; Forum, Venue and Jurisdiction
Our partnership agreement is governed by Delaware law. Our
partnership agreement requires that any claims, suits, actions
or proceedings:
|
|
|
|
|
arising out of or relating in any way to the partnership
agreement (including any claims, suits or actions to interpret,
apply or enforce the provisions of the partnership agreement or
the duties, obligations or liabilities among limited partners or
of limited partners to us, or the rights or powers of, or
restrictions on, the limited partners or us);
|
|
|
|
brought in a derivative manner on our behalf;
|
|
|
|
asserting a claim of breach of a fiduciary duty owed by any
director, officer or other employee of us or our general
partner, or owed by our general partner, to us or the limited
partners;
|
|
|
|
asserting a claim arising pursuant to any provision of the
Delaware Act; or
|
|
|
|
asserting a claim governed by the internal affairs doctrine,
|
shall be exclusively brought in the Court of Chancery of the
State of Delaware, regardless of whether such claims, suits,
actions or proceedings sound in contract, tort, fraud or
otherwise, are based on common law, statutory, equitable, legal
or other grounds, or are derivative or direct claims. By
purchasing a common unit, a limited partner is irrevocably
consenting to these limitations and provisions regarding claims,
suits, actions or proceedings and submitting to the exclusive
jurisdiction of the Court of Chancery of the State of Delaware
in connection with any such claims, suits, actions or
proceedings.
Limited
Liability
Assuming that a limited partner does not participate in the
control of our business within the meaning of the Delaware Act
and that he otherwise acts in conformity with the provisions of
our partnership agreement, his liability under the Delaware Act
will be limited, subject to possible exceptions, to the amount
of capital he is obligated to contribute to us for his common
units plus his share of any undistributed profits and assets. If
it were determined, however, that the right or exercise of the
right, by our limited partners as a group:
|
|
|
|
|
to remove or replace our general partner;
|
|
|
|
to approve some amendments to the partnership agreement; or
|
|
|
|
to take other action under the partnership agreement
|
constituted participation in the control of our
business for the purposes of the Delaware Act, then our limited
partners could be held personally liable for our obligations
under Delaware law, to the same extent as our general partner.
This liability would extend to persons who transact business
with us and reasonably believe that the limited partner is a
general partner. Neither our partnership agreement nor the
Delaware Act specifically provides for legal recourse against
our general partner if a limited partner were to lose limited
liability through any fault of our general partner. While this
does not mean that a limited partner could not seek legal
recourse, we know of no precedent for this type of a claim in
Delaware case law.
Under the Delaware Act, a limited partnership may not make a
distribution to a partner if, after the distribution, all
liabilities of the limited partnership, other than liabilities
to partners on account of their partnership interests and
liabilities for which the recourse of creditors is limited to
specific property of the
182
partnership, would exceed the fair value of the assets of the
limited partnership. For the purpose of determining the fair
value of the assets of a limited partnership, the Delaware Act
provides that the fair value of property subject to liability
for which recourse of creditors is limited shall be included in
the assets of the limited partnership only to the extent that
the fair value of that property exceeds the nonrecourse
liability. Moreover, under the Delaware Act, a limited
partnership may also not make a distribution to a partner upon
the winding up of the limited partnership before liabilities of
the limited partnership to creditors have been satisfied by
payment or the making of reasonable provision for payment
thereof. The Delaware Act provides that a limited partner who
receives a distribution and knew at the time of the distribution
that the distribution was in violation of the Delaware Act shall
be liable to the limited partnership for the amount of the
distribution for three years. Under the Delaware Act, a
substituted limited partner of a limited partnership is liable
for the obligations of his assignor to make contributions to the
partnership, except that such person is not obligated for
liabilities unknown to him at the time he became a limited
partner and that could not be ascertained from the partnership
agreement.
Our operating subsidiary currently conducts business in Texas
and Louisiana, and we may have operating subsidiaries that
conduct business in other states in the future. Maintenance of
our limited liability as a member of each of our operating
subsidiaries may require compliance with legal requirements in
the jurisdictions in which our operating subsidiaries conduct
business, including qualifying our operating subsidiaries to do
business there.
Limitations on the liability of limited partners for the
obligations of a limited partner have not been clearly
established in many jurisdictions. If, by virtue of our
ownership in the operating company or otherwise, it were
determined that we were conducting business in any state without
compliance with the applicable limited partnership or limited
liability company statute, or that the right or exercise of the
right by our limited partners as a group to remove or replace
our general partner, to approve some amendments to our
partnership agreement, or to take other action under our
partnership agreement constituted participation in the
control of our business for purposes of the statutes of
any relevant jurisdiction, then our limited partners could be
held personally liable for our obligations under the law of that
jurisdiction to the same extent as our general partner under the
circumstances. We will operate in a manner that our general
partner considers reasonable and necessary or appropriate to
preserve the limited liability of our limited partners.
Issuance
of Additional Securities
Our partnership agreement authorizes us to issue an unlimited
number of additional partnership securities for the
consideration and on the terms and conditions determined by our
general partner without the approval of our unitholders.
It is possible that we will fund acquisitions through the
issuance of additional common units or other partnership
securities. Holders of any additional common units we issue will
be entitled to share equally with the then-existing holders of
common units in our distributions of available cash. In
addition, the issuance of additional common units or other
partnership securities may dilute the value of the interests of
the then-existing holders of common units in our net assets.
In accordance with Delaware law and the provisions of our
partnership agreement, we may also issue additional partnership
securities that, as determined by our general partner, may have
special limited voting rights to which the common units are not
entitled. In addition, our partnership agreement does not
prohibit the issuance by our subsidiaries of equity securities,
which may effectively rank senior to our common units.
If we issue additional units in the future, our general partner
will be entitled, but not required, to make additional capital
contributions to the extent necessary to maintain its 0.1%
general partner interest in us. Our general partners 0.1%
general partner interest in us will be reduced if we issue
additional units in the future and our general partner does not
contribute a proportionate amount of capital to us to maintain
its 0.1% general partner interest in us. Moreover, our general
partner will have the right, which it may from time to time
assign in whole or in part to any of its affiliates, to purchase
common units or other partnership securities whenever, and on
the same terms that, we issue those securities to persons other
than our general partner and its affiliates, to the extent
necessary to maintain the aggregate percentage interest in us of
our general partner
183
and its affiliates, including such interest represented by
common units, that existed immediately prior to each issuance.
The holders of common units will not have preemptive rights to
acquire additional common units or other partnership securities.
Amendment
of the Partnership Agreement
General
Amendments to our partnership agreement may be proposed only by
or with the consent of our general partner. However, our general
partner will have no duty or obligation to propose any amendment
and may decline to do so free of any fiduciary duty or
obligation whatsoever to us or our limited partners, including
any duty to act in good faith or in the best interests of us or
our limited partners. To adopt a proposed amendment, other than
the amendments discussed below under No
Unitholder Approval, our general partner is required to
seek written approval of the holders of the number of units
required to approve the amendment or call a meeting of our
limited partners to consider and vote upon the proposed
amendment. Except as described below, an amendment must be
approved by a unit majority.
Prohibited
Amendments
No amendment may be made that would:
|
|
|
|
|
enlarge the obligations of any limited partner without its
consent, unless approved by at least a majority of the type or
class of limited partner interests so affected; or
|
|
|
|
enlarge the obligations of, restrict in any way any action by or
rights of, or reduce in any way the amounts distributable,
reimbursable or otherwise payable by us to our general partner
or any of its affiliates without the consent of our general
partner, which consent may be given or withheld in its sole
discretion.
|
The provision of our partnership agreement preventing the
amendments having the effects described in any of the clauses
above can be amended upon the approval of the holders of at
least 90% of the outstanding units voting together as a single
class (including units owned by our general partner and its
affiliates). Upon completion of this offering, Memorial Resource
will own approximately % of our
outstanding common units and all of our subordinated units,
representing an aggregate % limited
partner interest in us.
No
Unitholder Approval
Our general partner may generally make amendments to our
partnership agreement without the approval of any limited
partner or assignee to reflect:
|
|
|
|
|
a change in our name, the location of our principal place of
business, our registered agent or our registered office;
|
|
|
|
the admission, substitution, withdrawal or removal of partners
in accordance with our partnership agreement;
|
|
|
|
a change that our general partner determines to be necessary or
appropriate for us to qualify or to continue our qualification
as a limited partnership or other entity in which the limited
partners have limited liability under the laws of any state or
to ensure that neither we, nor any of our subsidiaries will be
treated as an association taxable as a corporation or otherwise
taxed as an entity for federal income tax purposes;
|
|
|
|
a change in our fiscal year or taxable year and related changes;
|
|
|
|
an amendment that is necessary, in the opinion of our counsel,
to prevent us or our general partner or the directors, officers,
agents or trustees of our general partner from in any manner
being subjected to the provisions of the Investment Company Act
of 1940, the Investment Advisors Act of 1940, or plan
asset regulations adopted under the Employee Retirement
Income Security Act of 1974, or ERISA, whether or not
substantially similar to plan asset regulations currently
applied or proposed;
|
184
|
|
|
|
|
an amendment that our general partner determines to be necessary
or appropriate for the authorization of additional partnership
securities or rights to acquire partnership securities;
|
|
|
|
any amendment expressly permitted in our partnership agreement
to be made by our general partner acting alone;
|
|
|
|
an amendment effected, necessitated or contemplated by a merger
agreement that has been approved under the terms of our
partnership agreement;
|
|
|
|
any amendment that our general partner determines to be
necessary or appropriate for the formation by us of, or our
investment in, any corporation, partnership or other entity, as
otherwise permitted by our partnership agreement;
|
|
|
|
any amendment necessary to require our limited partners to
provide a statement, certification or other evidence to us
regarding whether such limited partner is subject to United
States federal income taxation on the income generated by us and
to provide for the ability of our general partner to redeem the
units of any limited partner who fails to provide such
statement, certification or other evidence;
|
|
|
|
conversions into, mergers with or conveyances to another limited
liability entity that is newly formed and has no assets,
liabilities or operations at the time of the conversion, merger
or conveyance other than those it receives by way of the
conversion, merger or conveyance; or
|
|
|
|
any other amendments substantially similar to any of the matters
described in the clauses above.
|
In addition, our general partner may make amendments to our
partnership agreement without the approval of any limited
partner if our general partner determines that those amendments:
|
|
|
|
|
do not adversely affect our limited partners (or any particular
class of limited partners) in any material respect;
|
|
|
|
are necessary or appropriate to satisfy any requirements,
conditions or guidelines contained in any opinion, directive,
order, ruling or regulation of any federal or state agency or
judicial authority or contained in any federal or state statute;
|
|
|
|
are necessary or appropriate to facilitate the trading of our
limited partner interests or to comply with any rule,
regulation, guideline or requirement of any securities exchange
on which our limited partner interests are or will be listed for
trading;
|
|
|
|
are necessary or appropriate for any action taken by our general
partner relating to splits or combinations of units under the
provisions of our partnership agreement; or
|
|
|
|
are required to effect the intent expressed in this prospectus
or the intent of the provisions of the partnership agreement or
are otherwise contemplated by our partnership agreement.
|
Opinion
of Counsel and Unitholder Approval
For amendments of the type not requiring unitholder approval,
our general partner will not be required to obtain an opinion of
counsel that an amendment will not result in a loss of limited
liability to our limited partners or result in our being treated
as an association taxable as a corporation or otherwise taxable
as an entity for federal income tax purposes. No other
amendments to our partnership agreement will become effective
without the approval of holders of at least 90% of the
outstanding units unless we first obtain an opinion of counsel
to the effect that the amendment will not affect the limited
liability under applicable law of any of our limited partners.
In addition to the above restrictions, any amendment that would
have a material adverse effect on the rights or preferences of
any type or class of outstanding units in relation to other
classes of units will require the approval of at least a
majority of the type or class of units so affected. Any
amendment that reduces the voting percentage required to take
any action other than to remove the general partner or call a
meeting of unitholders is required to be approved by the
affirmative vote of limited partners whose aggregate outstanding
units constitute not less than the voting requirement sought to
be reduced.
185
Any amendment that would increase the percentage of units
required to remove the general partner or call a meeting of
unitholders must be approved by the affirmative vote of limited
partners whose aggregate outstanding units constitute not less
than the percentage sought to be increased.
Merger,
Consolidation, Conversion, Sale or Other Disposition of
Assets
A merger, consolidation or conversion of us requires the prior
consent of our general partner. However, our general partner
will have no duty or obligation to consent to any merger,
consolidation or conversion and may decline to do so free of any
fiduciary duty or obligation whatsoever to us or our limited
partners, including any duty to act in good faith or in the best
interest of us or our limited partners.
In addition, the partnership agreement generally prohibits our
general partner, without the prior approval of the holders of a
unit majority, from causing us to, among other things, sell,
exchange or otherwise dispose of all or substantially all of our
assets in a single transaction or a series of related
transactions, including by way of merger, consolidation or other
combination, or sale, exchange or other disposition of our
subsidiaries. Our general partner may, however, mortgage,
pledge, hypothecate or grant a security interest in all or
substantially all of our assets without that approval. Our
general partner may also sell all or substantially all of our
assets under a foreclosure or other realization upon those
encumbrances without the approval of a unit majority. Finally,
our general partner may consummate any merger, consolidation or
conversion without the prior approval of our unitholders if we
are the surviving entity in the transaction, our general partner
has received an opinion of counsel regarding limited liability
and tax matters, the transaction will not result in a material
amendment to our partnership agreement (other than an amendment
that the general partner could adopt without the consent of
other partners), each of our units will be an identical unit of
our partnership following the transaction, and the partnership
securities to be issued do not exceed 20% of our outstanding
partnership securities immediately prior to the transaction.
If the conditions specified in our partnership agreement are
satisfied, our general partner may convert us or any of our
subsidiaries into a new limited liability entity or merge us or
any of our subsidiaries into, or convey some or all of our
assets to, a newly formed entity, if the sole purpose of that
conversion, merger or conveyance is to effect a mere change in
our legal form into another limited liability entity, our
general partner has received an opinion of counsel regarding
limited liability and tax matters, and the governing instruments
of the new entity provide our limited partners and our general
partner with the same rights and obligations as contained in our
partnership agreement. The unitholders are not entitled to
dissenters rights of appraisal under our partnership
agreement or applicable Delaware law in the event of a
conversion, merger or consolidation, a sale of substantially all
of our assets or any other similar transaction or event.
Termination
and Dissolution
We will continue as a limited partnership until terminated under
our partnership agreement. We will dissolve upon:
|
|
|
|
|
the election of our general partner to dissolve us, if approved
by the holders of a unit majority;
|
|
|
|
there being no limited partners, unless we are continued without
dissolution in accordance with applicable Delaware law;
|
|
|
|
the entry of a decree of judicial dissolution of our
partnership; or
|
|
|
|
the withdrawal or removal of our general partner or any other
event that results in its ceasing to be our general partner
other than by reason of a transfer of its general partner
interest in us in accordance with our partnership agreement or
withdrawal or removal following approval and admission of a
successor.
|
Upon a dissolution under the last clause above, the holders of a
unit majority may also elect, within specific time limitations,
to continue our business on the same terms and conditions
described in our
186
partnership agreement by appointing as a successor general
partner an entity approved by a unit majority, subject to our
receipt of an opinion of counsel to the effect that:
|
|
|
|
|
the action would not result in the loss of limited liability
under Delaware law of any limited partner; and
|
|
|
|
neither our partnership nor any of our subsidiaries would be
treated as an association taxable as a corporation or otherwise
be taxable as an entity for federal income tax purposes upon the
exercise of that right to continue (to the extent not already so
treated or taxed).
|
Liquidation
and Distribution of Proceeds
Upon our dissolution, unless we are continued as a new limited
partnership, the liquidator authorized to wind up our affairs
will, acting with all of the powers of our general partner that
are necessary or appropriate, liquidate our assets and apply the
proceeds of the liquidation as described in Provisions of
Our Partnership Agreement Relating to Cash
Distributions Distributions of Cash Upon
Liquidation. The liquidator may defer liquidation or
distribution of our assets for a reasonable period of time or
distribute assets to partners in kind if it determines that a
sale would be impractical or would cause undue loss to our
partners.
Withdrawal
or Removal of Our General Partner
Except as described below, our general partner has agreed not to
withdraw voluntarily as our general partner prior
to ,
2021 without obtaining the approval of the holders of at least a
majority of our outstanding common units, excluding common units
held by our general partner and its affiliates, and furnishing
an opinion of counsel regarding limited liability and tax
matters. On or
after ,
2021, our general partner may withdraw as our general partner
without first obtaining approval of any unitholder by giving
90 days written notice, and that withdrawal will not
constitute a violation of our partnership agreement.
Notwithstanding the information above, our general partner may
withdraw as our general partner without unitholder approval upon
90 days notice to our limited partners if at least
50% of the outstanding common units are held or controlled by
one person and its affiliates other than our general partner and
its affiliates. In addition, our partnership agreement permits
our general partner in some instances to sell or otherwise
transfer all of its general partner interest in us without the
approval of the unitholders. Please read
Transfer of General Partner Units.
Upon withdrawal of our general partner under any circumstances,
other than as a result of a transfer by our general partner of
all or a part of its general partner interest in us, the holders
of a majority of our outstanding units may select a successor to
the withdrawing general partner. If a successor is not elected,
or is elected but an opinion of counsel regarding limited
liability and tax matters cannot be obtained, we will be
dissolved, wound up and liquidated, unless within a specified
period of time after that withdrawal, the holders of a majority
of our outstanding common units, excluding the common units held
by the withdrawing general partner and its affiliates, agree in
writing to continue our business and to appoint a successor
general partner. Please read Termination and
Dissolution.
Our general partner may not be removed unless that removal is
approved by the vote of the holders of not less than
662/3%
of our outstanding units, including units held by our general
partner and its affiliates, and we receive an opinion of counsel
regarding limited liability and tax matters. Any removal of our
general partner is also subject to the approval of a successor
general partner by the vote of the holders of a majority of our
outstanding common units, including common units held by our
general partner and its affiliates. The ownership of more than
331/3%
of our outstanding units by our general partner and its
affiliates would give them the practical ability to prevent our
general partners removal. At the closing of this offering,
Memorial Resource will own
approximately % of our outstanding
common units and 100% of our subordinated units representing an
aggregate % limited partner
interest in us.
187
Our partnership agreement also provides that if our general
partner is removed as our general partner without cause and no
units held by our general partner and its affiliates are voted
in favor of that removal:
|
|
|
|
|
the subordination period will end and all outstanding
subordinated units will immediately convert into common units on
a
one-for-one
basis;
|
|
|
|
any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
|
|
|
|
our general partner will have the right to convert its general
partner interest and its incentive distribution rights into
common units or to receive cash in exchange for those interests
based on the fair market value of the interests at the time.
|
In the event of removal of our general partner under
circumstances where cause exists or withdrawal of our general
partner where that withdrawal violates our partnership
agreement, a successor general partner will have the option to
purchase the departing general partners general partner
interest and incentive distribution rights for a cash payment
equal to the fair market value of that interest. Under all other
circumstances where our general partner withdraws or is removed
by the limited partners, the departing general partner will have
the option to require the successor general partner to purchase
the departing general partners general partner interest
and incentive distribution rights for its fair market value.
In each case, this fair market value will be determined by
agreement between the departing general partner and the
successor general partner. If no agreement is reached, an
independent investment banking firm or other independent expert
selected by the departing general partner and the successor
general partner will determine the fair market value. If the
departing general partner and the successor general partner
cannot agree upon an expert, then an expert chosen by agreement
of the experts selected by each of them will determine the fair
market value.
If the option described above is not exercised by either the
departing general partner or the successor general partner, the
departing general partners general partner interest and
incentive distribution rights will automatically convert into
common units equal to the fair market value of that interest as
determined by an investment banking firm or other independent
expert selected in the manner described in the preceding
paragraph.
In addition, we will be required to reimburse the departing
general partner for all amounts due the departing general
partner, including, without limitation, all employee-related
liabilities, including severance liabilities, incurred for the
termination of any employees employed by the departing general
partner or its affiliates for our benefit.
Transfer
of General Partner Units
Except for the transfer by our general partner of all, but not
less than all, of its general partner units to:
|
|
|
|
|
an affiliate of our general partner (other than an
individual); or
|
|
|
|
another entity as part of the merger or consolidation of our
general partner with or into another entity or the transfer by
our general partner of all or substantially all of its assets to
another entity,
|
our general partner may not transfer all or any part of its
general partner units to another person, prior
to ,
2020, without the approval of the holders of at least a majority
of our outstanding common units, excluding common units held by
our general partner and its affiliates. As a condition of this
transfer, the transferee must assume, among other things, the
rights and duties of our general partner, agree to be bound by
the provisions of our partnership agreement, and furnish an
opinion of counsel regarding limited liability and tax matters.
Our general partner and its affiliates may at any time transfer
common units or subordinated units to one or more persons
without unitholder approval, except that they may not transfer
subordinated units to us.
188
Transfer
of Incentive Distribution Rights
Our general partner or any other holder of incentive
distribution rights may transfer any or all of its incentive
distribution rights without unitholder approval.
Transfer
of Ownership Interests in Our General Partner
At any time, the owner of our general partner may sell or
transfer all or part of its membership interest in our general
partner to an affiliate or a third party without the approval of
our unitholders.
Change of
Management Provisions
Our partnership agreement contains specific provisions that are
intended to discourage a person or group from attempting to
remove our general partner or otherwise change the management of
our general partner. If any person or group other than our
general partner and its affiliates acquires beneficial ownership
of 20% or more of any class of units, that person or group loses
limited voting rights on all of its units. This loss of limited
voting rights does not apply to any person or group that
acquires the units from our general partner or its affiliates
and any transferees of that person or group approved by our
general partner or to any person or group who acquires the units
with the prior approval of the board of directors of our general
partner.
Limited
Call Right
If at any time our general partner and its affiliates own more
than 80% of our then-issued and outstanding limited partner
interests of any class, our general partner will have the right,
which it may assign in whole or in part to any of its affiliates
or to us, to acquire all, but not less than all, of the limited
partner interests of the class held by unaffiliated persons as
of a record date to be selected by our general partner, on at
least 10 but not more than 60 days notice. The purchase
price in the event of this purchase is the greater of:
|
|
|
|
|
the highest cash price paid by either of our general partner or
any of its affiliates for any limited partner interests of the
class purchased within the 90 days preceding the date on
which our general partner first mails notice of its election to
purchase those limited partner interests; and
|
|
|
|
the current market price as of the date three days before the
date the notice is mailed.
|
As a result of our general partners right to purchase
outstanding limited partner interests, a holder of limited
partner interests may have his limited partner interests
purchased at a price that may be lower than market prices at
various times prior to such purchase or lower than a unitholder
may anticipate the market price to be in the future. The federal
income tax consequences to a unitholder of the exercise of this
call right are the same as a sale by that unitholder of his
common units in the market. Please read Material Tax
Consequences Disposition of Common Units.
Meetings;
Voting
Except as described below regarding a person or group owning 20%
or more of any class of units then outstanding, record holders
of units on the record date will be entitled to notice of, and
to vote at, meetings of our limited partners and to act upon
matters for which approvals may be solicited. In the case of
common units held by the general partner on behalf of
non-citizen assignees, the general partner will distribute the
votes on those common units in the same ratios as the votes of
limited partners on other units are cast.
Our general partner does not anticipate that any meeting of
unitholders will be called in the foreseeable future. Any action
that is required or permitted to be taken by the unitholders may
be taken either at a meeting of the unitholders or without a
meeting, if consents in writing describing the action so taken
are signed by holders of the number of units necessary to
authorize or take that action at a meeting. Meetings of the
unitholders may be called by our general partner or by
unitholders owning at least 20% of the outstanding units of the
class for which a meeting is proposed. Unitholders may vote
either in person or by proxy at meetings. The holders of a
majority of the outstanding units of the class or classes for
which a meeting has been called, represented in person or by
proxy, will constitute a quorum unless any action by the
unitholders
189
requires approval by holders of a greater percentage of the
units, in which case the quorum will be the greater percentage.
Each record holder of a unit has a vote according to his
percentage interest in us, although additional limited partner
interests having special limited voting rights could be issued.
Please read Issuance of Additional
Securities. However, if at any time any person or group,
other than our general partner and its affiliates or a direct or
subsequently approved transferee of our general partner or its
affiliates, acquires, in the aggregate, beneficial ownership of
20% or more of any class of units then outstanding, that person
or group will lose limited voting rights on all of its units and
the units may not be voted on any matter and will not be
considered to be outstanding when sending notices of a meeting
of unitholders, calculating required votes, determining the
presence of a quorum or for other similar purposes. Common units
held in nominee or street name account will be voted by the
broker or other nominee in accordance with the instruction of
the beneficial owner unless the arrangement between the
beneficial owner and his nominee provides otherwise.
Any notice, demand, request, report or proxy material required
or permitted to be given or made to record holders of common
units under our partnership agreement will be delivered to the
record holder by us or by the transfer agent.
Status as
Limited Partner
By transfer of any common units in accordance with our
partnership agreement, each transferee of common units shall be
admitted as a limited partner with respect to the common units
transferred when such transfer and admission is reflected in our
books and records. Except as described above under
Limited Liability, the common units will
be fully paid, and unitholders will not be required to make
additional contributions.
Non-Citizen
Assignees; Redemption
If we are or become subject to federal, state or local laws or
regulations that, in the reasonable determination of our general
partner, create a substantial risk of cancellation or forfeiture
of any property that we have an interest in because of the
nationality, citizenship or other related status of any limited
partner, we may redeem the units held by the limited partner at
their current market price. (This could occur, for example, if
in the future we own interests in oil and natural gas leases on
United States federal lands.) In order to avoid any cancellation
or forfeiture, our general partner may require any limited
partner or transferee to furnish information about his
nationality, citizenship or related status. If a limited partner
fails to furnish information about his nationality, citizenship
or other related status within 30 days after a request for
the information or our general partner determines after receipt
of the information that the limited partner is not an eligible
citizen, the limited partner may be treated as a non-citizen
assignee. A non-citizen assignee, is entitled to an interest
equivalent to that of a limited partner for the right to share
in allocations and distributions from us, including liquidating
distributions. A non-citizen assignee does not have the right to
direct the voting of his units and may not receive distributions
in-kind upon our liquidation.
In addition, in such circumstance, we will have the right to
acquire all (but not less than all) of the units held by such
limited partner or non-citizen assignee. The purchase price for
such units will be the average of the daily closing prices per
unit for the 20 consecutive trading days immediately prior to
the date set for such purchase, and such purchase price will be
paid (in the sole discretion of our general partner) either in
cash or by delivery of a promissory note. Any such promissory
note will bear interest at the rate of 5% annually and will be
payable in three equal annual installments of principal and
accrued interest, commencing one year after the purchase date.
Any such promissory note will also be unsecured and will be
subordinated to the extent required by the terms of our other
indebtedness.
Non-Taxpaying
Assignees; Redemption
If our general partner, with the advice of counsel, determines
that our not being treated as an association taxable as a
corporation or otherwise taxable as an entity for
U.S. federal income tax purposes, coupled with the tax
status (or lack of proof thereof) of one or more of our limited
partners, has, or is reasonably likely to
190
have, a material adverse effect on our ability to operate our
assets or generate revenues from our assets, then our general
partner may adopt such amendments to our partnership agreement
as it determines necessary or advisable to:
|
|
|
|
|
obtain proof of the U.S. federal income tax status of
limited partners (and their owners, to the extent
relevant); and
|
|
|
|
permit us to redeem the units at their current market price held
by any person whose tax status has or is reasonably likely to
have a material adverse effect on our ability to operate our
assets or generate revenues from our assets or who fails to
comply with the procedures instituted by our general partner to
obtain proof of the U.S. federal income tax status.
|
A non-taxpaying assignee does not have the right to direct the
voting of his units and may not receive distributions in-kind
upon our liquidation.
Indemnification
Under our partnership agreement, in most circumstances, we will
indemnify the following persons, to the fullest extent permitted
by law, from and against all losses, claims, damages or similar
events:
|
|
|
|
|
our general partner;
|
|
|
|
any departing general partner;
|
|
|
|
any person who is or was an affiliate of a general partner or
any departing general partner;
|
|
|
|
any person who is or was a director, officer, member, partner,
fiduciary or trustee of any entity set forth in the preceding
three bullet points;
|
|
|
|
any person who is or was serving as a director, officer, member,
partner, fiduciary or trustee of another person at the request
of our general partner or any departing general partner; and
|
|
|
|
any person designated by our general partner.
|
Any indemnification under these provisions will only be out of
our assets. Unless it otherwise agrees, our general partner will
not be personally liable for, or have any obligation to
contribute or lend funds or assets to us to enable us to
effectuate, indemnification. We may purchase insurance covering
liabilities asserted against and expenses incurred by persons
for our activities, regardless of whether we would have the
power to indemnify the person against liabilities under our
partnership agreement.
Reimbursement
of Expenses
Our partnership agreement requires us to reimburse our general
partner for all direct and indirect expenses it incurs or
payments it makes on our behalf and all other expenses allocable
to us or otherwise incurred by our general partner in connection
with operating our business. These expenses include salary,
bonus, incentive compensation, and other amounts paid to persons
who perform services for us or on our behalf, and expenses
allocated to our general partner by its affiliates. Our general
partner is entitled to determine in good faith the expenses that
are allocable to us.
Immediately prior to the closing of this offering, our general
partner will enter into a omnibus agreement pursuant to which,
among other things, Memorial Resource will agree to provide the
administrative, management, and acquisition advisory services
that we believe are necessary to allow our general partner to
manage, operate and grow our business, as well as the operating
services that we believe are necessary to develop and operate
our properties.
Books and
Reports
Our general partner is required to keep appropriate books of our
business at our principal offices. The books will be maintained
for both tax and financial reporting purposes on an accrual
basis. For financial reporting and tax purposes, our fiscal year
end is December 31.
191
We will furnish or make available to record holders of common
units, within 90 days after the close of each fiscal year,
an annual report containing audited financial statements and a
report on those financial statements by our independent
registered public accounting firm. Except for our fourth
quarter, we will also furnish or make available summary
financial information within 45 days after the close of
each quarter. We will be deemed to have made any such report
available if we file such report with the SEC on EDGAR or make
the report available on a publicly available website which we
maintain.
We will furnish each record holder of a unit with information
reasonably required for tax reporting purposes within
90 days after the close of each calendar year. This
information is expected to be furnished in summary form so that
some complex calculations normally required of partners can be
avoided. Our ability to furnish this summary information to our
unitholders will depend on the cooperation of our unitholders in
supplying us with specific information. Every unitholder will
receive information to assist him in determining his federal and
state tax liability and filing his federal and state income tax
returns, regardless of whether he supplies us with information.
Right to
Inspect Our Books and Records
Our partnership agreement provides that a limited partner can,
for a purpose reasonably related to his interest as a limited
partner, upon reasonable written demand stating the purpose of
such demand and at his own expense, obtain:
|
|
|
|
|
a current list of the name and last known address of each
partner;
|
|
|
|
a copy of our tax returns;
|
|
|
|
information as to the amount of cash, and a description and
statement of the agreed value of any other property or services,
contributed or to be contributed by each partner and the date on
which each partner became a partner;
|
|
|
|
copies of our partnership agreement, our certificate of limited
partnership, related amendments and powers of attorney under
which they have been executed;
|
|
|
|
information regarding the status of our business and financial
condition; and
|
|
|
|
any other information regarding our affairs as is just and
reasonable.
|
Our general partner may, and intends to, keep confidential from
the limited partners trade secrets or other information the
disclosure of which our general partner believes in good faith
is not in our best interests or that we are required by law or
by agreements with third parties to keep confidential.
Registration
Rights
Under our partnership agreement, we have agreed to register for
resale under the Securities Act and applicable state securities
laws any common units, subordinated units or other partnership
securities proposed to be sold by our general partner or any of
its affiliates or their assignees if an exemption from the
registration requirements is not otherwise available. In
addition, our general partner and its affiliates have the right
to include such securities in a registration by us or any other
unitholder, subject to customary exceptions. These registration
rights continue for two years following any withdrawal or
removal of our general partner. In addition, we are restricted
from granting any superior piggyback registration rights during
this two-year period. We are obligated to pay all expenses
incidental to the registration, excluding underwriting
discounts. In connection with any registration of this kind, we
will indemnify the unitholders participating in the registration
and their officers, directors and controlling persons from and
against specified liabilities, including under the Securities
Act or any applicable state securities laws. Please read
Units Eligible for Future Sale.
192
UNITS
ELIGIBLE FOR FUTURE SALE
After the sale of the common units offered hereby, Memorial
Resource will hold an aggregate
of common units
and subordinated
units. All of the subordinated units will convert into common
units at the end of the subordination period. The sale of these
units could have an adverse impact on the price of the common
units or on any trading market that may develop.
The common units sold in this offering will generally be freely
transferable without restriction or further registration under
the Securities Act, except that any common units owned by an
affiliate of ours may not be resold publicly except
in compliance with the registration requirements of the
Securities Act or under an exemption under Rule 144 or
otherwise. Rule 144 permits securities acquired by an
affiliate of the issuer to be sold into the market in an amount
that does not exceed, during any three-month period, the greater
of:
|
|
|
|
|
1.0% of the total number of the securities outstanding; or
|
|
|
|
the average weekly reported trading volume of the common units
for the four calendar weeks prior to the sale.
|
Sales under Rule 144 are also subject to specific manner of
sale provisions, holding period requirements, notice
requirements and the availability of current public information
about us. A unitholder who is not deemed to have been an
affiliate of ours at any time during the three months preceding
a sale, and who has beneficially owned his common units for at
least six months (provided we are in compliance with the current
public information requirement) or one year (regardless of
whether we are in compliance with the current public information
requirement), would be entitled to sell his common units under
Rule 144 without regard to the rules public
information requirements, volume limitations, manner of sale
provisions and notice requirements.
Our partnership agreement does not restrict our ability to issue
any partnership interests. Any issuance of additional common
units or other equity interests would result in a corresponding
decrease in the proportionate ownership interest in us
represented by, and could adversely affect the cash
distributions to and market price of, our common units then
outstanding. Please read The Partnership
Agreement Issuance of Additional Securities.
Under our partnership agreement, our general partner and its
affiliates have the right to cause us to register under the
Securities Act and applicable state securities laws the offer
and sale of any common units or other partnership interests that
they hold, which we refer to as registerable securities. Subject
to the terms and conditions of our partnership agreement, these
registration rights allow our general partner and its affiliates
or their assignees holding any registerable securities to
require registration of such registerable securities and to
include any such registerable securities in a registration by us
of common units or other partnership interests, including common
units or other partnership interests offered by us or by any
unitholder. Our general partner and its affiliates will continue
to have these registration rights for two years following the
withdrawal or removal of our general partner. In connection with
any registration of units held by our general partner or its
affiliates, we will indemnify each unitholder participating in
the registration and its officers, directors, and controlling
persons from and against any liabilities under the Securities
Act or any applicable state securities laws arising from the
registration statement or prospectus. We will bear all costs and
expenses incidental to any registration, excluding any
underwriting discounts. Except as described below, our general
partner and its affiliates may sell their common units or other
partnership interests in private transactions at any time,
subject to compliance with certain conditions and applicable
laws.
We, our general partner and certain of its affiliates and the
directors and executive officers of our general partner have
agreed, subject to certain exceptions, not to sell any common
units for a period of 180 days from the date of this
prospectus. For a description of these
lock-up
provisions, please read Underwriting.
193
MATERIAL
TAX CONSEQUENCES
This section is a summary of the material tax considerations
that may be relevant to prospective unitholders who are
individual citizens or residents of the U.S. and, unless
otherwise noted in the following discussion, is the opinion of
Akin Gump Strauss Hauer & Feld LLP, counsel to our
general partner and us, insofar as it relates to legal
conclusions with respect to matters of U.S. federal income
tax law. This section is based upon current provisions of the
Internal Revenue Code of 1986, as amended, or the Internal
Revenue Code, existing and proposed Treasury regulations
promulgated under the Internal Revenue Code, or the Treasury
Regulations, and current administrative rulings and court
decisions, all of which are subject to change. Later changes in
these authorities may cause the tax consequences to vary
substantially from the consequences described below. Unless the
context otherwise requires, references in this section to
us or we are references to Memorial
Production Partners LP and our operating company.
The following discussion does not comment on all federal income
tax matters affecting us or our unitholders. Moreover, the
discussion focuses on unitholders who are individual citizens or
residents of the U.S. and has only limited application to
corporations, estates, trusts, nonresident aliens or other
unitholders subject to specialized tax treatment, such as
tax-exempt institutions, foreign persons, individual retirement
accounts, or IRAs, real estate investment trusts, or REITs, or
mutual funds. In addition, this discussion only comments to a
limited extent on state, local and foreign tax consequences.
Accordingly, we encourage each prospective unitholder to
consult, and depend on, his own tax advisor in analyzing the
federal, state, local and foreign tax consequences particular to
him of the ownership or disposition of common units.
No ruling has been or will be requested from the Internal
Revenue Service, or the IRS, regarding any matter affecting us
or prospective unitholders. Instead, we will rely on opinions of
Akin Gump Strauss Hauer & Feld LLP. Unlike a ruling,
an opinion of counsel represents only that counsels best
legal judgment and does not bind the IRS or the courts.
Accordingly, the opinions and statements made herein may not be
sustained by a court if contested by the IRS. Any contest of
this sort with the IRS may materially and adversely impact the
market for the common units and the prices at which common units
trade. In addition, the costs of any contest with the IRS,
principally legal, accounting and related fees, will result in a
reduction in available cash for distribution to our unitholders
and our general partner and thus will be borne indirectly by our
unitholders and our general partner. Furthermore, the tax
treatment of us, or of an investment in us, may be significantly
modified by future legislative or administrative changes or
court decisions. Any modifications may or may not be
retroactively applied.
All statements as to matters of law and legal conclusions, but
not as to factual matters, contained in this section, unless
otherwise noted, are the opinion of Akin Gump Strauss
Hauer & Feld LLP and are based on the accuracy of the
representations made by us.
For the reasons described below, Akin Gump Strauss
Hauer & Feld LLP has not rendered an opinion with
respect to the following specific federal income tax issues:
(i) the treatment of a unitholder whose common units are
loaned to a short seller to cover a short sale of common units
(please read Tax Consequences of Unit
Ownership Treatment of Short Sales);
(ii) whether our monthly convention for allocating taxable
income and losses is permitted by existing Treasury Regulations
(please read Disposition of Common
Units Allocations Between Transferors and
Transferees); and (iii) whether our method for
depreciating Section 743 adjustments is sustainable in
certain cases (please read Tax Consequences of
Unit Ownership Section 754 Election).
Partnership
Status
A partnership is not a taxable entity and incurs no federal
income tax liability. Instead, each partner of a partnership is
required to take into account his share of items of income,
gain, loss and deduction of the partnership in computing his
federal income tax liability, regardless of whether cash
distributions are made to him by the partnership. Distributions
by a partnership to a partner are generally not taxable to the
partnership or the partner unless the amount of cash distributed
to him is in excess of the partners adjusted basis in his
partnership interest.
194
Section 7704 of the Internal Revenue Code provides that
publicly traded partnerships will, as a general rule, be taxed
as corporations. However, an exception, referred to as the
Qualifying Income Exception, exists with respect to
publicly traded partnerships of which 90% or more of the gross
income for every taxable year consists of qualifying
income. Qualifying income includes income and gains
derived from the exploration, production, transportation,
storage and processing of crude oil, natural gas and products
thereof. Other types of qualifying income include interest
(other than from a financial business), dividends, gains from
the sale of real property and gains from the sale or other
disposition of capital assets held for the production of income
that otherwise constitutes qualifying income. We estimate that
less than % of our current gross
income is not qualifying income; however, this estimate could
change from time to time. Based upon and subject to this
estimate, the factual representations made by us and our general
partner and a review of the applicable legal authorities, Akin
Gump Strauss Hauer & Feld LLP is of the opinion that
at least 90% of our current gross income constitutes qualifying
income. The portion of our income that is qualifying income may
change from time to time.
No ruling has been or will be sought from the IRS and the IRS
has made no determination as to our status or the status of our
operating company for federal income tax purposes or whether our
operations generate qualifying income under
Section 7704 of the Internal Revenue Code. Instead, we will
rely on the opinion of Akin Gump Strauss Hauer & Feld
LLP on such matters. It is the opinion of Akin Gump Strauss
Hauer & Feld LLP that, based upon the Internal Revenue
Code, its regulations, published revenue rulings and court
decisions and the representations described below, we will be
classified as a partnership and our operating company will be
disregarded as an entity separate from us for federal income tax
purposes.
In rendering its opinion, Akin Gump Strauss Hauer &
Feld LLP has relied on factual representations made by us and
our general partner. The representations made by us and our
general partner upon which Akin Gump Strauss Hauer &
Feld LLP relied include the following:
|
|
|
|
|
Neither we nor the operating company has elected or will elect
to be treated as a corporation;
|
|
|
|
For each taxable year of our existence, more than 90% of our
gross income has been and will be income that Akin Gump Strauss
Hauer & Feld LLP has opined or will opine is
qualifying income within the meaning of
Section 7704(d) of the Internal Revenue Code; and
|
|
|
|
Each hedging transaction that we treat as resulting in
qualifying income has been and will be appropriately identified
as a hedging transaction pursuant to applicable Treasury
Regulations, and has been and will be associated with oil,
natural gas, or products thereof that are held or to be held by
us in activities that Akin Gump Strauss Hauer & Feld
LLP has opined or will opine result in qualifying income.
|
We believe that these representations have been true in the past
and expect that these representations will be true in the future.
If we fail to meet the Qualifying Income Exception, other than a
failure that is determined by the IRS to be inadvertent and that
is cured within a reasonable time after discovery (in which case
the IRS may also require us to make adjustments with respect to
our unitholders or pay other amounts), we will be treated as if
we had transferred all of our assets, subject to liabilities, to
a newly formed corporation, on the first day of the year in
which we fail to meet the Qualifying Income Exception, in return
for stock in that corporation, and then distributed that stock
to the unitholders in liquidation of their interests in us. This
deemed contribution and liquidation should be tax-free to
unitholders and us so long as we, at that time, do not have
liabilities in excess of the tax basis of our assets.
Thereafter, we would be treated as an association taxable as a
corporation for federal income tax purposes.
If we were treated as an association taxable as a corporation
for U.S. federal income tax purposes in any taxable year,
either as a result of a failure to meet the Qualifying Income
Exception or otherwise, our items of income, gain, loss and
deduction would be reflected only on our tax return rather than
being passed through to our unitholders, and our net income
would be taxed to us at corporate rates. In addition, any
distribution made to a unitholder would be treated as either
taxable dividend income, to the extent of our current and
accumulated earnings and profits, or, in the absence of earnings
and profits, a nontaxable return of capital, to
195
the extent of the unitholders tax basis in his common
units, or taxable capital gain, after the unitholders tax
basis in his common units is reduced to zero. Accordingly,
taxation as a corporation would result in a material reduction
in a unitholders cash flow and after-tax return and thus
would likely result in a substantial reduction of the value of
the units.
The discussion below is based on Akin Gump Strauss
Hauer & Feld LLPs opinion that we will be
classified as a partnership for federal income tax purposes.
Limited
Partner Status
Unitholders who have become limited partners of Memorial
Production Partners LP will be treated as partners of Memorial
Production Partners LP for federal income tax purposes. Also,
unitholders whose common units are held in street name or by a
nominee and who have the right to direct the nominee in the
exercise of all substantive rights attendant to the ownership of
their common units will be treated as partners of Memorial
Production Partners LP for federal income tax purposes.
A beneficial owner of common units whose units have been
transferred to a short seller to complete a short sale would
appear to lose his status as a partner with respect to those
units for federal income tax purposes. Please read
Tax Consequences of Unit Ownership
Treatment of Short Sales.
Items of our income, gain, deductions or losses would not appear
to be reportable by a unitholder who is not a partner for
federal income tax purposes, and any cash distributions received
by a unitholder who is not a partner for federal income tax
purposes would therefore appear to be fully taxable as ordinary
income. These holders are urged to consult their own tax
advisors with respect to their tax consequences of holding
common units in Memorial Production Partners LP. The references
to unitholders in the discussion that follows are to
persons who are treated as partners in Memorial Production
Partners LP for federal income tax purposes.
Tax
Consequences of Unit Ownership
Flow-Through
of Taxable Income
Subject to the discussion below under
Entity-Level Collections of Unitholder
Taxes, we will not pay any U.S. federal income tax.
Instead, each unitholder will be required to report on his
income tax return his share of our income, gains, losses and
deductions without regard to whether we make cash distributions
to him. Consequently, we may allocate income to a unitholder
even if he has not received a cash distribution. Each unitholder
will be required to include in income his allocable share of our
income, gains, losses and deductions for our taxable year ending
with or within his taxable year. Our taxable year ends on
December 31.
Treatment
of Distributions
Distributions made by us to a unitholder generally will not be
taxable to the unitholder for federal income tax purposes,
except to the extent the amount of any such cash distribution
exceeds his tax basis in his common units immediately before the
distribution. Our cash distributions in excess of a
unitholders tax basis generally will be considered to be
gain from the sale or exchange of the common units, taxable in
accordance with the rules described under
Disposition of Common Units below. Any
reduction in a unitholders share of our liabilities for
which no partner, including the general partner, bears the
economic risk of loss, known as nonrecourse
liabilities, will be treated as a distribution by us of
cash to that unitholder. To the extent our distributions cause a
unitholders at-risk amount to be less than
zero at the end of any taxable year, he must recapture any
losses deducted in previous years. Please read
Limitations on Deductibility of Losses.
A decrease in a unitholders percentage interest in us
because of our issuance of additional common units will decrease
his share of our nonrecourse liabilities, and thus will result
in a corresponding deemed distribution of cash. This deemed
distribution may constitute a non-pro rata distribution. A
non-pro rata distribution of money or property may result in
ordinary income to a unitholder, regardless of his tax basis in
his common units, if the distribution reduces the
unitholders share of our unrealized
receivables, including depreciation recapture,
and/or
substantially appreciated inventory items, both as
defined in the Internal
196
Revenue Code, and collectively, Section 751
Assets. To that extent, he will be treated as having been
distributed his proportionate share of the Section 751
Assets and then having exchanged those assets with us in return
for the non-pro rata portion of the actual distribution made to
him. This latter deemed exchange will generally result in the
unitholders realization of ordinary income, which will
equal the excess of (i) the non-pro rata portion of that
distribution over (ii) the unitholders tax basis
(generally zero) for the share of Section 751 Assets deemed
relinquished in the exchange.
Ratio
of Taxable Income to Distributions
We estimate that a purchaser of common units in this offering
who owns those common units from the date of closing of this
offering through the record date for distributions for the
period
ending ,
will be allocated, on a cumulative basis, an amount of federal
taxable income for that period that will
be % or less of the cash
distributed with respect to that period. Thereafter, we
anticipate that the ratio of taxable income to cash
distributions to the unitholders will increase. These estimates
are based upon the assumption that earnings from operations will
approximate the amount required to make the minimum quarterly
distribution on all units and other assumptions with respect to
capital expenditures, cash flow, net working capital and
anticipated cash distributions. These estimates and assumptions
are subject to, among other things, numerous business, economic,
regulatory, legislative, competitive and political uncertainties
beyond our control. Further, the estimates are based on current
federal income tax law and federal income tax reporting
positions that we will adopt and with which the IRS could
disagree. Accordingly, we cannot assure you that these estimates
will prove to be correct. The actual ratio of taxable income to
cash distributions could be higher or lower than expected, and
any differences could be material and could materially affect
the value of the common units. For example, the ratio of
allocable taxable income to cash distributions to a purchaser of
common units in this offering will be higher, and perhaps
substantially higher, than our estimate with respect to the
period described above if:
|
|
|
|
|
gross income from operations exceeds the amount required to make
minimum quarterly distributions on all units, yet we only
distribute the minimum quarterly distributions on all units;
|
|
|
|
we make a future offering of common units and use the proceeds
of the offering in a manner that does not produce substantial
additional deductions during the period described above, such as
to repay indebtedness outstanding at the time of this offering
or to acquire property that is not eligible for depreciation or
amortization for federal income tax purposes or that is
depreciable or amortizable at a rate significantly slower than
the rate applicable to our assets at the time of this offering;
or
|
|
|
|
legislation is passed in response to President Obamas
Budget Proposal for Fiscal Year 2012 that would limit or repeal
certain U.S. federal income tax preferences currently
available to oil and gas exploration and production companies.
Please read Tax Treatment of
Operations Recent Legislative Developments.
|
Basis
of Common Units
A unitholders initial tax basis for his common units will
be the amount he paid for the common units plus his share of our
nonrecourse liabilities. That basis will be increased by his
share of our income and by any increases in his share of our
nonrecourse liabilities. That basis will be decreased, but not
below zero, by distributions from us, by the unitholders
share of our losses, by any decreases in his share of our
nonrecourse liabilities and by his share of our expenditures
that are not deductible in computing taxable income and are not
required to be capitalized. A unitholder will have no share of
our debt that is recourse to our general partner, but will have
a share, generally based on his share of profits, of our
nonrecourse liabilities. Please read
Disposition of Common Units
Recognition of Gain or Loss.
Limitations
on Deductibility of Losses
The deduction by a unitholder of his share of our losses will be
limited to the tax basis in his units and, in the case of an
individual unitholder, estate, trust, or a corporate unitholder
(if more than 50% of the value of the corporate
unitholders stock is owned directly or indirectly by or
for five or fewer individuals or some
197
tax-exempt organizations) to the amount for which the unitholder
is considered to be at risk with respect to our
activities, if that is less than his tax basis. A common
unitholder subject to these limitations must recapture losses
deducted in previous years to the extent that distributions
cause his at-risk amount to be less than zero at the end of any
taxable year. Losses disallowed to a unitholder or recaptured as
a result of these limitations will carry forward and will be
allowable as a deduction to the extent that his at-risk amount
is subsequently increased, provided such losses do not exceed
such common unitholders tax basis in his common units.
Upon the taxable disposition of a unit, any gain recognized by a
unitholder can be offset by losses that were previously
suspended by the at-risk limitation but may not be offset by
losses suspended by the basis limitation. Any loss previously
suspended by the at-risk limitation in excess of that gain would
no longer be utilizable.
In general, a unitholder will be at risk to the extent of the
tax basis of his units, excluding any portion of that basis
attributable to his share of our nonrecourse liabilities,
reduced by (i) any portion of that basis representing
amounts otherwise protected against loss because of a guarantee,
stop loss agreement or other similar arrangement and
(ii) any amount of money he borrows to acquire or hold his
units, if the lender of those borrowed funds owns an interest in
us, is related to the unitholder or can look only to the units
for repayment. A unitholders at-risk amount will increase
or decrease as the tax basis of the unitholders units
increases or decreases, other than tax basis increases or
decreases attributable to increases or decreases in his share of
our nonrecourse liabilities.
The at-risk limitation applies on an
activity-by-activity
basis, and in the case of oil and natural gas properties, each
property is treated as a separate activity. Thus, a
taxpayers interest in each oil or natural gas property is
generally required to be treated separately so that a loss from
any one property would be limited to the at-risk amount for that
property and not the at-risk amount for all the taxpayers
oil and natural gas properties. It is uncertain how this rule is
implemented in the case of multiple oil and natural gas
properties owned by a single entity treated as a partnership for
federal income tax purposes. However, for taxable years ending
on or before the date on which further guidance is published,
the IRS will permit aggregation of oil or natural gas properties
we own in computing a unitholders at-risk limitation with
respect to us. If a unitholder were required to compute his
at-risk amount separately with respect to each oil or natural
gas property we own, he might not be allowed to utilize his
share of losses or deductions attributable to a particular
property even though he has a positive at-risk amount with
respect to his units as a whole.
In addition to the basis and at-risk limitations on the
deductibility of losses, the passive loss limitations generally
provide that individuals, estates, trusts and some closely-held
corporations and personal service corporations can deduct losses
from passive activities, which are generally trade or business
activities in which the taxpayer does not materially
participate, only to the extent of the taxpayers income
from those passive activities. The passive loss limitations are
applied separately with respect to each publicly traded
partnership. Consequently, any passive losses we generate will
only be available to offset our passive income generated in the
future and will not be available to offset income from other
passive activities or investments, including our investments or
a unitholders investments in other publicly traded
partnerships, or salary or active business income. Passive
losses that are not deductible because they exceed a
unitholders share of income we generate may be deducted in
full when he disposes of his entire investment in us in a fully
taxable transaction with an unrelated party. The passive
activity loss limitations are applied after other applicable
limitations on deductions, including the at-risk rules and the
basis limitation.
A unitholders share of our net income may be offset by any
of our suspended passive losses, but it may not be offset by any
other current or carryover losses from other passive activities,
including those attributable to other publicly traded
partnerships.
Limitations
on Interest Deductions
The deductibility of a non-corporate taxpayers
investment interest expense is generally limited to
the amount of that taxpayers net investment
income. Investment interest expense includes:
|
|
|
|
|
interest on indebtedness properly allocable to property held for
investment;
|
198
|
|
|
|
|
our interest expense attributed to portfolio income; and
|
|
|
|
the portion of interest expense incurred to purchase or carry an
interest in a passive activity to the extent attributable to
portfolio income.
|
The computation of a unitholders investment interest
expense will take into account interest on any margin account
borrowing or other loan incurred to purchase or carry a unit.
Net investment income includes gross income from property held
for investment and amounts treated as portfolio income under the
passive loss rules, less deductible expenses, other than
interest, directly connected with the production of investment
income, but generally does not include gains attributable to the
disposition of property held for investment or (if applicable)
qualified dividend income. The IRS has indicated that the net
passive income earned by a publicly traded partnership will be
treated as investment income to its unitholders for purposes of
the investment interest expense limitation. In addition, the
unitholders share of our portfolio income will be treated
as investment income.
Entity-Level Collections
of Unitholder Taxes
If we are required or elect under applicable law to pay any
federal, state, local or foreign income tax on behalf of any
unitholder or our general partner or any former unitholder, we
are authorized to pay those taxes from our funds. That payment,
if made, will be treated as a distribution of cash to the
unitholder on whose behalf the payment was made. If the payment
is made on behalf of a person whose identity cannot be
determined, we are authorized to treat the payment as a
distribution to all current unitholders. We are authorized to
amend our partnership agreement in the manner necessary to
maintain uniformity of intrinsic tax characteristics of units
and to adjust later distributions, so that after giving effect
to these distributions, the priority and characterization of
distributions otherwise applicable under our partnership
agreement is maintained as nearly as is practicable. Payments by
us as described above could give rise to an overpayment of tax
on behalf of an individual unitholder in which event the
unitholder would be required to file a claim in order to obtain
a credit or refund.
Allocation
of Income, Gain, Loss and Deduction
In general, if we have a net profit, our items of income, gain,
loss and deduction will be allocated among our general partner
and the unitholders in accordance with their percentage
interests in us. At any time that distributions are made to the
common units in excess of distributions to the subordinated
units, or incentive distributions are made to our general
partner, gross income will be allocated to the recipients to the
extent of these distributions. If we have a net loss, that loss
will be allocated first to our general partner and the
unitholders in accordance with their percentage interests in us
to the extent of their positive capital accounts and, second, to
our general partner.
Specified items of our income, gain, loss and deduction will be
allocated to account for (i) any difference between the tax
basis and fair market value of our assets at the time of an
offering and (ii) any difference between the tax basis and
fair market value of any property contributed to us by the
general partner and its affiliates that exists at the time of
such contribution, together, referred to in this discussion as
the Contributed Property. The effect of these
allocations, referred to as Section 704(c) Allocations, to
a unitholder purchasing common units from us in this offering
will be essentially the same as if the tax bases of our assets
were equal to their fair market values at the time of this
offering. In the event we issue additional common units or
engage in certain other transactions in the future,
reverse Section 704(c) Allocations, similar to
the Section 704(c) Allocations described above, will be
made to the general partner and our other unitholders
immediately prior to such issuance or other transactions to
account for the difference between the book basis
for purposes of maintaining capital accounts and the fair market
value of all property held by us at the time of such issuance or
future transaction. In addition, items of recapture income will
be allocated to the extent possible to the unitholder who was
allocated the deduction giving rise to the treatment of that
gain as recapture income in order to minimize the recognition of
ordinary income by some unitholders. Finally, although we do not
expect that our operations will result in the creation of
negative capital accounts, if
199
negative capital accounts nevertheless result, items of our
income and gain will be allocated in an amount and manner
sufficient to eliminate the negative balance as quickly as
possible.
An allocation of items of our income, gain, loss or deduction,
other than an allocation required by the Internal Revenue Code
to eliminate the difference between a partners
book capital account, credited with the fair market
value of Contributed Property, and tax capital
account, credited with the tax basis of Contributed Property,
referred to in this discussion as the Book-Tax
Disparity, will generally be given effect for federal
income tax purposes in determining a partners share of an
item of income, gain, loss or deduction only if the allocation
has substantial economic effect. In any other case, a
partners share of an item will be determined on the basis
of his interest in us, which will be determined by taking into
account all the facts and circumstances, including:
|
|
|
|
|
his relative contributions to us;
|
|
|
|
the interests of all the partners in profits and losses;
|
|
|
|
the interest of all the partners in cash flow; and
|
|
|
|
the rights of all the partners to distributions of capital upon
liquidation.
|
Akin Gump Strauss Hauer & Feld LLP is of the opinion
that, with the exception of the issues described in
Section 754 Election and
Disposition of Common Units
Allocations Between Transferors and Transferees,
allocations under our partnership agreement will be given effect
for federal income tax purposes in determining a partners
share of an item of income, gain, loss or deduction.
Treatment
of Short Sales
A unitholder whose units are loaned to a short
seller to cover a short sale of units may be considered as
having disposed of those units. If so, he would no longer be
treated for tax purposes as a partner with respect to those
units during the period of the loan and may recognize gain or
loss from the disposition. As a result, during this period:
|
|
|
|
|
any of our income, gain, loss or deduction with respect to those
units would not be reportable by the unitholder;
|
|
|
|
any cash distributions received by the unitholder as to those
units would be fully taxable; and
|
|
|
|
all of these distributions may be subject to ordinary income tax.
|
Akin Gump Strauss Hauer & Feld LLP has not rendered an
opinion regarding the tax treatment of a unitholder whose common
units are loaned to a short seller to cover a short sale of
common units; therefore, unitholders desiring to assure their
status as partners and avoid the risk of gain recognition from a
loan to a short seller are urged to modify any applicable
brokerage account agreements to prohibit their brokers from
borrowing and loaning their units. The IRS has announced that it
is studying issues relating to the tax treatment of short sales
of partnership interests. Please also read
Disposition of Common Units
Recognition of Gain or Loss.
Alternative
Minimum Tax
Each unitholder will be required to take into account his
distributive share of any items of our income, gain, loss or
deduction for purposes of the alternative minimum tax. The
current minimum tax rate for noncorporate taxpayers is 26% on
the first $175,000 of alternative minimum taxable income in
excess of the exemption amount and 28% on any additional
alternative minimum taxable income. Prospective unitholders are
urged to consult with their tax advisors as to the impact of an
investment in units on their liability for the alternative
minimum tax.
200
Tax
Rates
Under current law, the highest marginal U.S. federal income
tax rate applicable to ordinary income of individuals is 35% and
the highest marginal U.S. federal income tax rate
applicable to long-term capital gains (generally, capital gains
on certain assets held for more than twelve months) of
individuals is 15%. However, absent new legislation extending
the current rates, beginning January 1, 2013, the highest
marginal U.S. federal income tax rate applicable to
ordinary income and long-term capital gains of individuals will
increase to 39.6% and 20%, respectively. Moreover, these rates
are subject to change by new legislation at any time.
A 3.8% Medicare tax on certain investment income earned by
individuals, estates and trusts will apply for taxable years
beginning after December 31, 2012. For these purposes,
investment income generally includes a unitholders
allocable share of our income and any gain realized by a
unitholder from a sale of units. In the case of an individual,
the tax will be imposed on the lesser of (i) the
unitholders net investment income from all investments or
(ii) the amount by which the unitholders modified
adjusted gross income exceeds $250,000 (if the unitholder is
married and filing jointly or a surviving spouse), $125,000 (if
the unitholder is married and filed separately) or $200,000 (in
any other case). In the case of an estate or trust, the tax will
be imposed on the lesser of (i) undistributed net
investment income or (ii) the excess adjusted gross income
over the dollar amount at which the highest income tax bracket
applicable to an estate or trust begins.
Section 754
Election
We will make the election permitted by Section 754 of the
Internal Revenue Code. This election is irrevocable without the
consent of the IRS unless there is a technical termination of
the partnership. Please read Disposition of
Common Units Constructive Termination. The
election will generally permit us to adjust a common unit
purchasers tax basis in our assets (inside
basis) under Section 743(b) of the Internal Revenue
Code to reflect his purchase price. This election does not apply
to a person who purchases common units directly from us. The
Section 743(b) adjustment belongs to the purchaser and not
to other unitholders. For purposes of this discussion, a
unitholders inside basis in our assets will be considered
to have two components: (i) his share of our tax basis in
our assets (common basis) and (ii) his
Section 743(b) adjustment to that basis.
We will adopt the remedial allocation method as to all our
properties. Where the remedial allocation method is adopted, the
Treasury Regulations under Section 743 of the Internal
Revenue Code require a portion of the Section 743(b)
adjustment that is attributable to recovery property subject to
depreciation under Section 168 of the Internal Revenue Code
whose book basis is in excess of its tax basis to be depreciated
over the remaining cost recovery period for the propertys
unamortized Book-Tax Disparity. Under Treasury
Regulation Section 1.167(c)-1(a)(6),
a Section 743(b) adjustment attributable to property
subject to depreciation under Section 167 of the Internal
Revenue Code, rather than cost recovery deductions under
Section 168, is generally required to be depreciated using
either the straight-line method or the 150% declining balance
method. Under our partnership agreement, our general partner is
authorized to take a position to preserve the uniformity of
units even if that position is not consistent with these and any
other Treasury Regulations. Please read
Uniformity of Units.
Although Akin Gump Strauss Hauer & Feld LLP is unable
to opine as to the validity of this approach because there is no
direct or indirect controlling authority on this issue, we
intend to depreciate the portion of a Section 743(b)
adjustment attributable to unrealized appreciation in the value
of Contributed Property, to the extent of any unamortized
Book-Tax Disparity, using a rate of depreciation or amortization
derived from the depreciation or amortization method and useful
life applied to the propertys unamortized Book-Tax
Disparity, or treat that portion as
non-amortizable
to the extent attributable to property which is not amortizable.
This method is consistent with the methods employed by other
publicly traded partnerships but is arguably inconsistent with
Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets. To the extent this Section 743(b) adjustment is
attributable to appreciation in value in excess of the
unamortized Book-Tax Disparity, we will apply the rules
described in the Treasury Regulations and legislative history.
If we determine that this position cannot reasonably be taken,
we may take
201
a depreciation or amortization position under which all
purchasers acquiring units in the same month would receive
depreciation or amortization, whether attributable to common
basis or a Section 743(b) adjustment, based upon the same
applicable rate as if they had purchased a direct interest in
our assets. This kind of aggregate approach may result in lower
annual depreciation or amortization deductions than would
otherwise be allowable to some unitholders. Please read
Uniformity of Units. A unitholders
tax basis for his common units is reduced by his share of our
deductions (whether or not such deductions were claimed on an
individuals income tax return) so that any position we
take that understates deductions will overstate the common
unitholders basis in his common units, which may cause the
unitholder to understate gain or overstate loss on any sale of
such units. Please read Disposition of Common
Units Recognition of Gain or Loss. The IRS may
challenge our position with respect to depreciating or
amortizing the Section 743(b) adjustment we take to
preserve the uniformity of the units. If such a challenge were
sustained, the gain from the sale of units might be increased
without the benefit of additional deductions.
A Section 754 election is advantageous if the
transferees tax basis in his units is higher than the
units share of the aggregate tax basis of our assets
immediately prior to the transfer. In that case, as a result of
the election, the transferee would have, among other items, a
greater amount of depreciation deductions and his share of any
gain or loss on a sale of our assets would be less. Conversely,
a Section 754 election is disadvantageous if the
transferees tax basis in his units is lower than those
units share of the aggregate tax basis of our assets
immediately prior to the transfer. Thus, the fair market value
of the units may be affected either favorably or unfavorably by
the election. A basis adjustment is required regardless of
whether a Section 754 election is made in the case of a
transfer of an interest in us if we have a substantial built-in
loss immediately after the transfer, or if we distribute
property and have a substantial basis reduction. Generally a
built-in loss or a basis reduction is substantial if it exceeds
$250,000.
The calculations involved in the Section 754 election are
complex and will be made on the basis of assumptions as to the
fair market value of our assets and other matters. For example,
the allocation of the Section 743(b) adjustment among our
assets must be made in accordance with the Internal Revenue
Code. The IRS could seek to reallocate some or all of any
Section 743(b) adjustment allocated by us to our tangible
assets to goodwill instead. Goodwill, as an intangible asset, is
generally nonamortizable or amortizable over a longer period of
time or under a less accelerated method than our tangible
assets. We cannot assure you that the determinations we make
will not be successfully challenged by the IRS and that the
deductions resulting from them will not be reduced or disallowed
altogether. Should the IRS require a different basis adjustment
to be made, and should, in our opinion, the expense of
compliance exceed the benefit of the election, we may seek
permission from the IRS to revoke our Section 754 election.
If permission is granted, a subsequent purchaser of units may be
allocated more income than he would have been allocated had the
election not been revoked.
Tax
Treatment of Operations
Accounting
Method and Taxable Year
We will use the year ending December 31 as our taxable year and
the accrual method of accounting for federal income tax
purposes. Each unitholder will be required to include in income
his share of our income, gain, loss and deduction for our
taxable year ending within or with his taxable year. In
addition, a unitholder who has a taxable year ending on a date
other than December 31 and who disposes of all of his units
following the close of our taxable year but before the close of
his taxable year must include his share of our income, gain,
loss and deduction in income for his taxable year, with the
result that he will be required to include in income for his
taxable year his share of more than twelve months of our income,
gain, loss and deduction. Please read
Disposition of Common Units
Allocations Between Transferors and Transferees.
Depletion
Deductions
Subject to the limitations on deductibility of losses discussed
above (please read Tax Consequences of Unit
Ownership Limitations on Deductibility of
Losses), unitholders will be entitled to deductions for
202
the greater of either cost depletion or (if otherwise allowable)
percentage depletion with respect to our oil and natural gas
interests. Although the Internal Revenue Code requires each
unitholder to compute his own depletion allowance and maintain
records of his share of the adjusted tax basis of the underlying
property for depletion and other purposes, we intend to furnish
each of our unitholders with information relating to this
computation for federal income tax purposes. Each unitholder,
however, remains responsible for calculating his own depletion
allowance and maintaining records of his share of the adjusted
tax basis of the underlying property for depletion and other
purposes.
Percentage depletion is generally available with respect to
unitholders who qualify under the independent producer exemption
contained in Section 613A(c) of the Internal Revenue Code.
For this purpose, an independent producer is a person not
directly or indirectly involved in the retail sale of oil,
natural gas, or derivative contracts or the operation of a major
refinery. Percentage depletion is calculated as an amount
generally equal to 15% (and, in the case of marginal production,
potentially a higher percentage) of the unitholders gross
income from the depletable property for the taxable year. The
percentage depletion deduction with respect to any property is
limited to 100% of the taxable income of the unitholder from the
property for each taxable year, computed without the depletion
allowance. A unitholder that qualifies as an independent
producer may deduct percentage depletion only to the extent the
unitholders average net daily production of domestic crude
oil, or the natural gas equivalent, does not exceed
1,000 barrels. This depletable amount may be allocated
between oil and natural gas production, with 6,000 cubic feet of
domestic natural gas production regarded as equivalent to one
barrel of crude oil. The 1,000-barrel limitation must be
allocated among the independent producer and controlled or
related persons and family members in proportion to the
respective production by such persons during the period in
question.
In addition to the foregoing limitations, the percentage
depletion deduction otherwise available is limited to 65% of a
unitholders total taxable income from all sources for the
year, computed without the depletion allowance, net operating
loss carrybacks, or capital loss carrybacks. Any percentage
depletion deduction disallowed because of the 65% limitation may
be deducted in the following taxable year if the percentage
depletion deduction for such year plus the deduction carryover
does not exceed 65% of the unitholders total taxable
income for that year. The carryover period resulting from the
65% net income limitation is unlimited.
Unitholders that do not qualify under the independent producer
exemption are generally restricted to depletion deductions based
on cost depletion. Cost depletion deductions are calculated by
(i) dividing the unitholders share of the adjusted
tax basis in the underlying mineral property by the number of
mineral units (barrels of oil and thousand cubic feet, or Mcf,
of natural gas) remaining as of the beginning of the taxable
year and (ii) multiplying the result by the number of
mineral units sold within the taxable year. The total amount of
deductions based on cost depletion cannot exceed the
unitholders share of the total adjusted tax basis in the
property.
All or a portion of any gain recognized by a unitholder as a
result of either the disposition by us of some or all of our oil
and natural gas interests or the disposition by the unitholder
of some or all of his units may be taxed as ordinary income to
the extent of recapture of depletion deductions, except for
percentage depletion deductions in excess of the tax basis of
the property. The amount of the recapture is generally limited
to the amount of gain recognized on the disposition.
The foregoing discussion of depletion deductions does not
purport to be a complete analysis of the complex legislation and
Treasury Regulations relating to the availability and
calculation of depletion deductions by the unitholders. Further,
because depletion is required to be computed separately by each
unitholder and not by our partnership, no assurance can be
given, and counsel is unable to express any opinion, with
respect to the availability or extent of percentage depletion
deductions to the unitholders for any taxable year. Moreover,
the availability of percentage depletion may be reduced or
eliminated if recently proposed (or similar) tax legislation is
enacted. For a discussion of such legislative proposals, please
read Recent Legislative Developments. We
encourage each prospective unitholder to consult his tax advisor
to determine whether percentage depletion would be available to
him.
203
Deductions
for Intangible Drilling and Development Costs
We will elect to currently deduct intangible drilling and
development costs, or IDCs. IDCs generally include our expenses
for wages, fuel, repairs, hauling, supplies and other items that
are incidental to, and necessary for, the drilling and
preparation of wells for the production of oil, natural gas, or
geothermal energy. The option to currently deduct IDCs applies
only to those items that do not have a salvage value.
Although we will elect to currently deduct IDCs, each unitholder
will have the option of either currently deducting IDCs or
capitalizing all or part of the IDCs and amortizing them on a
straight-line basis over a
60-month
period, beginning with the taxable month in which the
expenditure is made. If a unitholder makes the election to
amortize the IDCs over a
60-month
period, no IDC preference amount in respect of those IDCs will
result for alternative minimum tax purposes.
Integrated oil companies must capitalize 30% of all their IDCs
(other than IDCs paid or incurred with respect to oil and
natural gas wells located outside of the United States) and
amortize these IDCs over 60 months beginning in the month
in which those costs are paid or incurred. If the taxpayer
ceases to be an integrated oil company, it must continue to
amortize those costs as long as it continues to own the property
to which the IDCs relate. An integrated oil company
is a taxpayer that has economic interests in oil or natural gas
properties and also carries on substantial retailing or refining
operations. An oil or natural gas producer is deemed to be a
substantial retailer or refiner if it is subject to the rules
disqualifying retailers and refiners from taking percentage
depletion. To qualify as an independent producer
that is not subject to these IDC deduction limits, a unitholder,
either directly or indirectly through certain related parties,
may not be involved in the refining of more than
75,000 barrels of oil (or the equivalent amount of natural
gas) on average for any day during the taxable year or in the
retail marketing of oil and natural gas products exceeding
$5 million per year in the aggregate.
IDCs previously deducted that are allocable to property
(directly or through ownership of an interest in a partnership)
and that would have been included in the adjusted tax basis of
the property had the IDC deduction not been taken are recaptured
to the extent of any gain realized upon the disposition of the
property or upon the disposition by a unitholder of interests in
us. Recapture is generally determined at the unitholder level.
Where only a portion of the recapture property is sold, any IDCs
related to the entire property are recaptured to the extent of
the gain realized on the portion of the property sold. In the
case of a disposition of an undivided interest in a property, a
proportionate amount of the IDCs with respect to the property is
treated as allocable to the transferred undivided interest to
the extent of any gain recognized. Please read
Disposition of Common Units
Recognition of Gain or Loss.
The election to currently deduct IDCs may be restricted or
eliminated if recently proposed (or similar) tax legislation is
enacted. For a discussion of such legislative proposals, please
read Recent Legislative
Developments.
Deduction
for U.S. Production Activities
Subject to the limitations on the deductibility of losses
discussed above and the limitation discussed below, unitholders
will be entitled to a deduction, herein referred to as the
Section 199 deduction, equal to 6% of our qualified
production activities income that is allocated to such
unitholder, but not to exceed 50% of such unitholders IRS
Form W-2
wages for the taxable year allocable to domestic production
gross receipts.
Qualified production activities income is generally equal to
gross receipts from domestic production activities reduced by
cost of goods sold allocable to those receipts, other expenses
directly associated with those receipts, and a share of other
deductions, expenses and losses that are not directly allocable
to those receipts or another class of income. The products
produced must be manufactured, produced, grown or extracted in
whole or in significant part by the taxpayer in the United
States.
For a partnership, the Section 199 deduction is determined
at the partner level. To determine his Section 199
deduction, each unitholder will aggregate his share of the
qualified production activities income allocated to him from us
with the unitholders qualified production activities
income from other sources. Each unitholder must take into
account his distributive share of the expenses allocated to him
from our qualified
204
production activities regardless of whether we otherwise have
taxable income. However, our expenses that otherwise would be
taken into account for purposes of computing the
Section 199 deduction are taken into account only if and to
the extent the unitholders share of losses and deductions
from all of our activities is not disallowed by the tax basis
rules, the at-risk rules or the passive activity loss rules.
Please read Tax Consequences of Unit
Ownership Limitations on Deductibility of
Losses.
The amount of a unitholders Section 199 deduction for
each year is limited to 50% of the IRS
Form W-2
wages actually or deemed paid by the unitholder during the
calendar year that are deducted in arriving at qualified
production activities income. Each unitholder is treated as
having been allocated IRS
Form W-2
wages from us equal to the unitholders allocable share of
our wages that are deducted in arriving at qualified production
activities income for that taxable year. It is not anticipated
that we or our subsidiaries will pay material wages that will be
allocated to our unitholders, and thus a unitholders
ability to claim the Section 199 deduction may be limited.
This discussion of the Section 199 deduction does not
purport to be a complete analysis of the complex legislation and
Treasury authority relating to the calculation of domestic
production gross receipts, qualified production activities
income, or IRS
Form W-2
wages, or how such items are allocated by us to unitholders.
Further, because the Section 199 deduction is required to
be computed separately by each unitholder, no assurance can be
given, and counsel is unable to express any opinion, as to the
availability or extent of the Section 199 deduction to the
unitholders. Moreover, the availability of Section 199
deductions may be reduced or eliminated if recently proposed (or
similar) tax legislation is enacted. For a discussion of such
legislative proposals, please read Recent
Legislative Developments. Each prospective unitholder is
encouraged to consult his tax advisor to determine whether the
Section 199 deduction would be available to him.
Lease
Acquisition Costs
The cost of acquiring oil and natural gas lease or similar
property interests is a capital expenditure that must be
recovered through depletion deductions if the lease is
productive. If a lease is proved worthless and abandoned, the
cost of acquisition less any depletion claimed may be deducted
as an ordinary loss in the year the lease becomes worthless.
Please read Tax Treatment of
Operations Depletion Deductions.
Geophysical
Costs
The cost of geophysical exploration incurred in connection with
the exploration and development of oil and natural gas
properties in the United States are deducted ratably over a
24-month
period beginning on the date that such expense is paid or
incurred.
Operating
and Administrative Costs
Amounts paid for operating a producing well are deductible as
ordinary business expenses, as are administrative costs to the
extent they constitute ordinary and necessary business expenses
that are reasonable in amount.
Recent
Legislative Developments
The White House recently released President Obamas budget
proposal for the Fiscal Year 2012 (the Budget
Proposal). Among the changes recommended in the Budget
Proposal is the elimination of certain key U.S. federal
income tax preferences relating to oil and natural gas
exploration and development. Changes in the Budget Proposal
include, but are not limited to, (i) the repeal of the
percentage depletion allowance for oil and natural gas
properties, (ii) the elimination of current deductions for
IDCs, (iii) the elimination of the deduction for certain
domestic production activities, and (iv) an extension of
the amortization period for certain geological and geophysical
expenditures. Each of these changes is proposed to be effective
for taxable years beginning, or in the case of costs described
in (ii) and (iv), costs paid or incurred, after
December 31, 2011. It is unclear whether these or similar
changes will be enacted and, if enacted, how soon any such
changes could become effective. The passage of any legislation
as a result of these proposals or any other similar changes in
U.S. federal income tax laws could eliminate or postpone
certain tax deductions that are
205
currently available with respect to oil and natural gas
exploration and development, and any such change could increase
the taxable income allocable to our unitholders and negatively
impact the value of an investment in our units.
Initial
Tax Basis, Depreciation and Amortization
The tax basis of our assets will be used for purposes of
computing depreciation and cost recovery deductions and,
ultimately, gain or loss on the disposition of these assets. The
federal income tax burden associated with the difference between
the fair market value of our assets and their tax basis
immediately prior to (i) this offering will be borne by our
general partner and its affiliates, and (ii) any other
offering will be borne by our general partner and other
unitholders as of that time. Please read Tax
Consequences of Unit Ownership Allocation of Income,
Gain, Loss and Deduction.
To the extent allowable, we may elect to use the depreciation
and cost recovery methods, including bonus depreciation to the
extent available, that will result in the largest deductions
being taken in the early years after assets subject to these
allowances are placed in service. Please read
Uniformity of Units. Property we
subsequently acquire or construct may be depreciated using
accelerated methods permitted by the Internal Revenue Code.
If we dispose of depreciable property by sale, foreclosure or
otherwise, all or a portion of any gain, determined by reference
to the amount of depreciation previously deducted and the nature
of the property, may be subject to the recapture rules and taxed
as ordinary income rather than capital gain. Similarly, a
unitholder who has taken cost recovery or depreciation
deductions with respect to property we own will likely be
required to recapture some or all of those deductions as
ordinary income upon a sale of his interest in us. Please read
Tax Consequences of Unit Ownership
Allocation of Income, Gain, Loss and Deduction and
Disposition of Common Units
Recognition of Gain or Loss.
The costs we incur in selling our units (called
syndication expenses) must be capitalized and cannot
be deducted currently, ratably or upon our termination. There
are uncertainties regarding the classification of costs as
organization expenses, which may be amortized by us, and as
syndication expenses, which may not be amortized by us. The
underwriting discounts and commissions we incur will be treated
as syndication expenses.
Valuation
and Tax Basis of Our Properties
The federal income tax consequences of the ownership and
disposition of units will depend in part on our estimates of the
relative fair market values, and the initial tax bases, of our
assets. Although we may from time to time consult with
professional appraisers regarding valuation matters, we will
make many of the relative fair market value estimates ourselves.
These estimates and determinations of basis are subject to
challenge and will not be binding on the IRS or the courts. If
the estimates of fair market value or basis are later found to
be incorrect, the character and amount of items of income, gain,
loss or deduction previously reported by unitholders might
change, and unitholders might be required to adjust their tax
liability for prior years and incur interest and penalties with
respect to those adjustments.
Disposition
of Common Units
Recognition
of Gain or Loss
Gain or loss will be recognized on a sale of units equal to the
difference between the amount realized and the unitholders
tax basis for the units sold. A unitholders amount
realized will be measured by the sum of the cash or the fair
market value of other property received by him plus his share of
our nonrecourse liabilities. Because the amount realized
includes a unitholders share of our nonrecourse
liabilities, the gain recognized on the sale of units could
result in a tax liability in excess of any cash received from
the sale.
Prior distributions from us that in the aggregate were in excess
of cumulative net taxable income for a common unit that
decreased a unitholders tax basis in that common unit
will, in effect, become taxable income if the common unit is
sold at a price greater than the unitholders tax basis in
that common unit, even if the price received is less than his
original cost.
206
Except as noted below, gain or loss recognized by a unitholder,
other than a dealer in units, on the sale or
exchange of a unit will generally be taxable as capital gain or
loss. Capital gain recognized by an individual on the sale of
units held for more than twelve months will generally be taxed
at a maximum U.S. federal income tax rate of 15% through
December 31, 2012 and 20% thereafter (absent new
legislation extending or adjusting the current rate). However, a
portion of this gain or loss, which will likely be substantial,
will be separately computed and taxed as ordinary income or loss
under Section 751 of the Internal Revenue Code to the
extent attributable to assets giving rise to depreciation
recapture or other unrealized receivables or to
inventory items we own. The term unrealized
receivables includes potential recapture items, including
depreciation recapture. Ordinary income attributable to
unrealized receivables, inventory items and depreciation
recapture may exceed net taxable gain realized upon the sale of
a unit and may be recognized even if there is a net taxable loss
realized on the sale of a unit. Thus, a unitholder may recognize
both ordinary income and a capital loss upon a sale of units.
Capital losses may offset capital gains and no more than $3,000
of ordinary income, in the case of individuals, and may only be
used to offset capital gains in the case of corporations.
The IRS has ruled that a partner who acquires interests in a
partnership in separate transactions must combine those
interests and maintain a single adjusted tax basis for all those
interests. Upon a sale or other disposition of less than all of
those interests, a portion of that tax basis must be allocated
to the interests sold using an equitable
apportionment method, which generally means that the tax
basis allocated to the interest sold equals an amount that bears
the same relation to the partners tax basis in his entire
interest in the partnership as the value of the interest sold
bears to the value of the partners entire interest in the
partnership. Treasury Regulations under Section 1223 of the
Internal Revenue Code allow a selling unitholder who can
identify common units transferred with an ascertainable holding
period to elect to use the actual holding period of the common
units transferred. Thus, according to the ruling discussed
above, a common unitholder will be unable to select high or low
basis common units to sell as would be the case with corporate
stock, but, according to the Treasury Regulations, he may
designate specific common units sold for purposes of determining
the holding period of units transferred. A unitholder electing
to use the actual holding period of common units transferred
must consistently use that identification method for all
subsequent sales or exchanges of common units. A unitholder
considering the purchase of additional units or a sale of common
units purchased in separate transactions is urged to consult his
tax advisor as to the possible consequences of this ruling and
application of the Treasury Regulations.
Specific provisions of the Internal Revenue Code affect the
taxation of some financial products and securities, including
partnership interests, by treating a taxpayer as having sold an
appreciated partnership interest, one in which gain
would be recognized if it were sold, assigned or terminated at
its fair market value, if the taxpayer or related persons
enter(s) into:
|
|
|
|
|
a short sale;
|
|
|
|
an offsetting notional principal contract; or
|
|
|
|
a futures or forward contract with respect to the partnership
interest or substantially identical property.
|
Moreover, if a taxpayer has previously entered into a short
sale, an offsetting notional principal contract or a futures or
forward contract with respect to the partnership interest, the
taxpayer will be treated as having sold that position if the
taxpayer or a related person then acquires the partnership
interest or substantially identical property. The Secretary of
the Treasury is also authorized to issue regulations that treat
a taxpayer that enters into transactions or positions that have
substantially the same effect as the preceding transactions as
having constructively sold the financial position.
Allocations
Between Transferors and Transferees
In general, our taxable income and losses will be determined
annually, will be prorated on a monthly basis and will be
subsequently apportioned among the unitholders in proportion to
the number of units owned by each of them as of the opening of
the applicable exchange on the first business day of the month,
which we refer to in this prospectus as the Allocation
Date. However, in the discretion of our general partner,
gain or loss realized on a sale or other disposition of our
assets or any other extraordinary items of income, gain,
207
loss or deduction will be allocated among the unitholders on the
Allocation Date in the month in which such income, gain, loss or
deduction is recognized. As a result, a unitholder transferring
units may be allocated income, gain, loss and deduction realized
after the date of transfer.
Although simplifying conventions are contemplated by the
Internal Revenue Code and most publicly traded partnerships use
similar simplifying conventions, the use of this method may not
be permitted under existing Treasury Regulations. Recently,
however, the Department of the Treasury and the IRS issued
proposed Treasury Regulations that provide a safe harbor
pursuant to which a publicly traded partnership may use a
similar monthly simplifying convention to allocate tax items
among transferor and transferee unitholders, although such tax
items must be prorated on a daily basis. Nonetheless, the
proposed regulations do not specifically authorize the use of
the proration method we have adopted. Existing publicly traded
partnerships are entitled to rely on these proposed Treasury
Regulations; however, they are not binding on the IRS and are
subject to change until final Treasury Regulations are issued.
Accordingly, Akin Gump Strauss Hauer & Feld LLP is
unable to opine on the validity of this method of allocating
income and deductions between transferor and transferee
unitholders. If this method is not allowed under the Treasury
Regulations, or only applies to transfers of less than all of
the unitholders interest, our taxable income or losses
might be reallocated among the unitholders. We are authorized to
revise our method of allocation between transferor and
transferee unitholders, as well as unitholders whose interests
vary during a taxable year, to conform to a method permitted
under future Treasury Regulations.
A unitholder who owns units at any time during a quarter and who
disposes of them prior to the record date set for a cash
distribution for that quarter will be allocated items of our
income, gain, loss and deductions attributable to that quarter
but will not be entitled to receive that cash distribution.
Notification
Requirements
A unitholder who sells any of his units is generally required to
notify us in writing of that sale within 30 days after the
sale (or, if earlier, January 15 of the year following the
sale). A purchaser of units who purchases units from another
unitholder is also generally required to notify us in writing of
that purchase within 30 days after the purchase. Upon
receiving such notifications, we are required to notify the IRS
of that transaction and to furnish specified information to the
transferor and transferee. Failure to notify us of a purchase
may, in some cases, lead to the imposition of penalties.
However, these reporting requirements do not apply to a sale by
an individual who is a citizen of the U.S. and who effects
the sale or exchange through a broker who will satisfy such
requirements.
Constructive
Termination
We will be considered to have technically terminated for tax
purposes if there are sales or exchanges which, in the
aggregate, constitute 50% or more of the total interests in our
capital and profits within a twelve-month period. For purposes
of measuring whether the 50% threshold is reached, multiple
sales of the same interest are counted only once. A constructive
termination results in the closing of our taxable year for all
unitholders. In the case of a unitholder reporting on a taxable
year other than a fiscal year ending December 31, the
closing of our taxable year may result in more than twelve
months of our taxable income or loss being includable in his
taxable income for the year of termination. A constructive
termination occurring on a date other than December 31 will
result in us filing two tax returns (and unitholders receiving
two Schedules K-1, if the relief discussed below is unavailable)
for one fiscal year and the cost of the preparation of these
returns will be borne by all common unitholders. We would be
required to make new tax elections after a termination,
including a new election under Section 754 of the Internal
Revenue Code, and a termination would result in a deferral of
our deductions for depreciation. A termination could also result
in penalties if we were unable to determine that the termination
had occurred. Moreover, a termination might either accelerate
the application of, or subject us to, any tax legislation
enacted before the termination. The IRS has recently announced a
relief procedure whereby if a publicly traded partnership that
has technically terminated requests and the IRS grants special
relief, among other things, the partnership will be required to
provide only a single
Schedule K-1
to unitholders for the tax years in which the termination occurs.
208
Uniformity
of Units
Because we cannot match transferors and transferees of units, we
must maintain uniformity of the economic and tax characteristics
of the units to a purchaser of these units. In the absence of
uniformity, we may be unable to completely comply with a number
of federal income tax requirements, both statutory and
regulatory. A lack of uniformity can result from a literal
application of Treasury
Regulation Section 1.167(c)-1(a)(6).
Any non-uniformity could have a negative impact on the value of
the units. Please read Tax Consequences of
Unit Ownership Section 754 Election.
We intend to depreciate the portion of a Section 743(b)
adjustment attributable to unrealized appreciation in the value
of Contributed Property, to the extent of any unamortized
Book-Tax Disparity, using a rate of depreciation or amortization
derived from the depreciation or amortization method and useful
life applied to the propertys unamortized Book-Tax
Disparity, or treat that portion as nonamortizable, to the
extent attributable to property the common basis of which is not
amortizable, consistent with the regulations under
Section 743 of the Internal Revenue Code, even though that
position may be inconsistent with Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets. Please read Tax Consequences of
Unit Ownership Section 754 Election. To
the extent that the Section 743(b) adjustment is
attributable to appreciation in value in excess of the
unamortized Book-Tax Disparity, we will apply the rules
described in the Treasury Regulations and legislative history.
If we determine that this position cannot reasonably be taken,
we may adopt a depreciation and amortization position under
which all purchasers acquiring units in the same month would
receive depreciation and amortization deductions, whether
attributable to a common basis or Section 743(b)
adjustment, based upon the same applicable methods and lives as
if they had purchased a direct interest in our property. If this
position is adopted, it may result in lower annual depreciation
and amortization deductions than would otherwise be allowable to
some unitholders and risk the loss of depreciation and
amortization deductions not taken in the year that these
deductions are otherwise allowable. This position will not be
adopted if we determine that the loss of depreciation and
amortization deductions will have a material adverse effect on
the unitholders. If we choose not to utilize this aggregate
method, we may use any other reasonable depreciation and
amortization method to preserve the uniformity of the intrinsic
tax characteristics of any units that would not have a material
adverse effect on the unitholders. The IRS may challenge any
method of depreciating the Section 743(b) adjustment
described in this paragraph. If this challenge were sustained,
the uniformity of units might be affected, and the gain from the
sale of units might be increased without the benefit of
additional deductions. Please read Disposition
of Common Units Recognition of Gain or Loss.
Tax-Exempt
Organizations and Other Investors
Ownership of units by employee benefit plans, other tax-exempt
organizations, non-resident aliens, foreign corporations and
other foreign persons raises issues unique to those investors
and, as described below, may have substantially adverse tax
consequences to them. If you are a tax-exempt entity or a
non-U.S. person,
you should consult your tax advisor before investing in our
common units.
Employee benefit plans and most other organizations exempt from
federal income tax, including individual retirement accounts and
other retirement plans, are subject to federal income tax on
unrelated business taxable income. Virtually all of our income
allocated to a unitholder that is a tax-exempt organization will
be unrelated business taxable income and will be taxable to them.
Non-resident aliens and foreign corporations, trusts or estates
that own units will be considered to be engaged in business in
the United States because of the ownership of units. As a
consequence, they will be required to file federal tax returns
to report their share of our income, gain, loss or deduction and
pay federal income tax at regular rates on their share of our
net income or gain. Moreover, under rules applicable to publicly
traded partnerships, distributions to non-U.S. unitholders are
subject to withholding at the highest applicable effective tax
rate. Each non-U.S. unitholder must obtain a taxpayer
identification number from the IRS and submit that number to our
transfer agent on a
Form W-8BEN
or applicable substitute form in order to obtain credit for
these withholding taxes. A change in applicable law may require
us to change these procedures.
209
In addition, because a foreign corporation that owns units will
be treated as engaged in a U.S. trade or business, that
corporation may be subject to the U.S. branch profits tax
at a rate of 30%, in addition to regular federal income tax, on
its share of our income and gain, as adjusted for changes in the
foreign corporations U.S. net equity,
which is effectively connected with the conduct of a
U.S. trade or business. That tax may be reduced or
eliminated by an income tax treaty between the U.S. and the
country in which the foreign corporate unitholder is a
qualified resident. In addition, this type of
unitholder is subject to special information reporting
requirements under Section 6038C of the Internal Revenue
Code.
A foreign unitholder who sells or otherwise disposes of a common
unit will be subject to U.S. federal income tax on gain
realized from the sale or disposition of that unit to the extent
the gain is effectively connected with a U.S. trade or
business of the foreign unitholder. Under a ruling published by
the IRS, interpreting the scope of effectively connected
income, a foreign unitholder would be considered to be
engaged in a trade or business in the United States by virtue of
the U.S. activities of the partnership, and part or all of
that unitholders gain would be effectively connected with
that unitholders indirect U.S. trade or business.
Moreover, under the Foreign Investment in Real Property Tax Act,
a foreign common unitholder generally will be subject to
U.S. federal income tax upon the sale or disposition of a
common unit if (i) he owned (directly or constructively
applying certain attribution rules) more than 5% of our common
units at any time during the five-year period ending on the date
of such disposition and (ii) 50% or more of the fair market
value of all of our assets consisted of U.S. real property
interests at any time during the shorter of the period during
which such unitholder held the common units or the five-year
period ending on the date of disposition. Currently, more than
50% of our assets consist of U.S. real property interests
and we do not expect that to change in the foreseeable future.
Therefore, foreign unitholders may be subject to federal income
tax on gain from the sale or disposition of their units.
Administrative
Matters
Information
Returns and Audit Procedures
We intend to furnish to each unitholder, within 90 days
after the close of each calendar year, specific tax information,
including a
Schedule K-1,
which describes his share of our income, gain, loss and
deduction for our preceding taxable year. In preparing this
information, which will not be reviewed by counsel, we will take
various accounting and reporting positions, some of which have
been mentioned earlier, to determine each unitholders
share of income, gain, loss and deduction. We cannot assure you
that those positions will yield a result that conforms to the
requirements of the Internal Revenue Code, Treasury Regulations
or administrative interpretations of the IRS. Neither we nor
Akin Gump Strauss Hauer & Feld LLP can assure
prospective unitholders that the IRS will not successfully
contend in court that those positions are impermissible. Any
challenge by the IRS could negatively affect the value of the
units.
The IRS may audit our federal income tax information returns.
Adjustments resulting from an IRS audit may require each
unitholder to adjust a prior years tax liability, and
possibly may result in an audit of his return. Any audit of a
unitholders return could result in adjustments not related
to our returns as well as those related to our returns.
Partnerships generally are treated as separate entities for
purposes of federal tax audits, judicial review of
administrative adjustments by the IRS and tax settlement
proceedings. The tax treatment of partnership items of income,
gain, loss and deduction are determined in a partnership
proceeding rather than in separate proceedings with the
partners. The Internal Revenue Code requires that one partner be
designated as the Tax Matters Partner for these
purposes. Our partnership agreement names Memorial Production
Partners GP LLC, our general partner, as our Tax Matters Partner.
The Tax Matters Partner has made and will make some elections on
our behalf and on behalf of unitholders. In addition, the Tax
Matters Partner can extend the statute of limitations for
assessment of tax deficiencies against unitholders for items in
our returns. The Tax Matters Partner may bind a unitholder with
less than a 1% profits interest in us to a settlement with the
IRS unless that unitholder elects, by filing a statement with
the IRS, not to give that authority to the Tax Matters Partner.
The Tax Matters Partner may seek judicial review, by which all
the unitholders are bound, of a final partnership administrative
adjustment
210
and, if the Tax Matters Partner fails to seek judicial review,
judicial review may be sought by any unitholder having at least
a 1% interest in profits or by any group of unitholders having
in the aggregate at least a 5% interest in profits. However,
only one action for judicial review will go forward, and each
unitholder with an interest in the outcome may participate.
A unitholder must file a statement with the IRS identifying the
treatment of any item on his federal income tax return that is
not consistent with the treatment of the item on our return.
Intentional or negligent disregard of this consistency
requirement may subject a unitholder to substantial penalties.
Nominee
Reporting
Persons who hold an interest in us as a nominee for another
person are required to furnish to us:
|
|
|
|
|
the name, address and taxpayer identification number of the
beneficial owner and the nominee;
|
|
|
|
a statement regarding whether the beneficial owner is:
|
|
|
|
|
|
a person that is not a U.S. person;
|
|
|
|
a foreign government, an international organization or any
wholly owned agency or instrumentality of either of the
foregoing; or
|
|
|
|
a tax-exempt entity;
|
|
|
|
|
|
the amount and description of units held, acquired or
transferred for the beneficial owner; and
|
|
|
|
specific information including the dates of acquisitions and
transfers, means of acquisitions and transfers, and acquisition
cost for purchases, as well as the amount of net proceeds from
sales.
|
Brokers and financial institutions are required to furnish
additional information, including whether they are
U.S. persons and specific information on units they
acquire, hold or transfer for their own account. A penalty of
$100 per failure, up to a maximum of $1,500,000 per calendar
year, is imposed by the Internal Revenue Code for failure to
report that information to us. The nominee is required to supply
the beneficial owner of the units with the information furnished
to us.
Accuracy-Related
Penalties
An additional tax equal to 20% of the amount of any portion of
an underpayment of tax that is attributable to one or more
specified causes, including negligence or disregard of rules or
regulations, substantial understatements of income tax and
substantial valuation misstatements, is imposed by the Internal
Revenue Code. No penalty will be imposed, however, for any
portion of an underpayment if it is shown that there was a
reasonable cause for that portion and that the taxpayer acted in
good faith regarding that portion.
For individuals, a substantial understatement of income tax in
any taxable year exists if the amount of the understatement
exceeds the greater of 10% of the tax required to be shown on
the return for the taxable year or $5,000 ($10,000 for most
corporations). The amount of any understatement subject to
penalty generally is reduced if any portion is attributable to a
position adopted on the return:
|
|
|
|
|
for which there is, or was, substantial
authority; or
|
|
|
|
as to which there is a reasonable basis and the pertinent facts
of that position are disclosed on the return.
|
If any item of income, gain, loss or deduction included in the
distributive shares of unitholders might result in that kind of
an understatement of income for which no
substantial authority exists, we must disclose the
pertinent facts on our return. In addition, we will make a
reasonable effort to furnish sufficient information for
unitholders to make adequate disclosure on their returns and to
take other actions as may be appropriate to permit unitholders
to avoid liability for this penalty. More stringent rules apply
to tax shelters, which we do not believe includes
us, or any of our investments, plans or arrangements.
A substantial valuation misstatement exists if (a) the
value of any property, or the adjusted basis of any property,
claimed on a tax return is 150% or more of the amount determined
to be the correct amount of the
211
valuation or adjusted basis, (b) the price for any property
or services (or for the use of property) claimed on any such
return with respect to any transaction between persons described
in Internal Revenue Code Section 482 is 200% or more (or
50% or less) of the amount determined under Section 482 to
be the correct amount of such price, or (c) the net
Internal Revenue Code Section 482 transfer price adjustment
for the taxable year exceeds the lesser of $5 million or
10% of the taxpayers gross receipts.
No penalty is imposed unless the portion of the underpayment
attributable to a substantial valuation misstatement exceeds
$5,000 ($10,000 for most corporations). If the valuation claimed
on a return is 200% or more than the correct valuation, the
penalty imposed increases to 40%. We do not anticipate making
any valuation misstatements.
In addition, the 20% accuracy-related penalty also applies to
any portion of an underpayment of tax that is attributable to
transactions lacking economic substance. To the extent that such
transactions are not disclosed, the penalty imposed is increased
to 40%. Additionally, there is not reasonable cause defense to
the imposition of this penalty to such transactions.
Reportable
Transactions
If we were to engage in a reportable transaction, we
(and possibly you and others) would be required to make a
detailed disclosure of the transaction to the IRS. A transaction
may be a reportable transaction based upon any of several
factors, including the fact that it is a type of tax avoidance
publicly identified by the IRS as a listed
transaction or that it produces certain kinds of losses
for partnerships, individuals, S corporations, and trusts
in excess of $2 million in any single year, or
$4 million in any combination of 6 successive tax years.
Our participation in a reportable transaction could increase the
likelihood that our federal income tax information return (and
possibly your tax return) would be audited by the IRS. Please
read Information Returns and Audit
Procedures.
Moreover, if we were to participate in a reportable transaction
with a significant purpose to avoid or evade tax, or in any
listed transaction, you may be subject to the following:
|
|
|
|
|
accuracy-related penalties with a broader scope, significantly
narrower exceptions, and potentially greater amounts than
described above at Accuracy-Related
Penalties;
|
|
|
|
for those persons otherwise entitled to deduct interest on
federal tax deficiencies, nondeductibility of interest on any
resulting tax liability; and
|
|
|
|
in the case of a listed transaction, an extended statute of
limitations.
|
We do not expect to engage in any reportable
transactions.
State,
Local and Other Tax Considerations
In addition to federal income taxes, you likely will be subject
to other taxes, such as state and local income taxes,
unincorporated business taxes, and estate, inheritance or
intangible taxes that may be imposed by the various
jurisdictions in which we do business or own property or in
which you are a resident. Although an analysis of those various
taxes is not presented here, each prospective unitholder should
consider their potential impact on his investment in us.
Initially, we will own property or do business in Louisiana and
Texas. We may own property or do business in a number of
jurisdictions in the future. Generally, each of the states in
which we might do business, other than Texas, imposes a personal
income tax on individuals. Most of these states also impose an
income tax on corporations and other entities. Although you may
not be required to file a return and pay taxes in some
jurisdictions because your income from that jurisdiction falls
below the filing and payment requirement, you will be required
to file income tax returns and to pay income taxes in many of
these jurisdictions in which we do business or own property and
may be subject to penalties for failure to comply with those
requirements. In some jurisdictions, tax losses may not produce
a tax benefit in the year incurred and may not be available to
offset income in subsequent taxable years. Some of the
jurisdictions may require us, or we may elect, to withhold a
percentage of income from amounts to be distributed to a
unitholder who is not a resident of the jurisdiction.
Withholding, the amount of which may be
212
greater or less than a particular unitholders income tax
liability to the jurisdiction, generally does not relieve a
nonresident unitholder from the obligation to file an income tax
return. Amounts withheld may be treated as if distributed to
unitholders for purposes of determining the amounts distributed
by us. Please read Tax Consequences of
Unit Ownership Entity-Level Collections of
Unitholder Taxes. Based on current law and our estimate of
our future operations, our general partner anticipates that any
amounts required to be withheld will not be material.
The personal tax consequences of an investment in us may vary
among unitholders under the laws of pertinent jurisdictions and,
therefore, each prospective unitholder is urged to consult, and
depend upon, his tax counsel or other advisor with regard to
those matters. Further, it is the responsibility of each
unitholder to file all state, local and foreign, as well as
U.S. federal, tax returns that may be required of him. Akin
Gump Strauss Hauer & Feld LLP has not rendered an
opinion on the state, local or foreign tax consequences of an
investment in us.
213
INVESTMENT
IN MEMORIAL PRODUCTION PARTNERS LP BY EMPLOYEE BENEFIT
PLANS
An investment in us by an employee benefit plan is subject to
additional considerations because the investments of these plans
are subject to the fiduciary responsibility and prohibited
transaction provisions of ERISA and the restrictions imposed by
Section 4975 of the Internal Revenue Code and provisions
under any federal, state, local,
non-U.S. or
other laws or regulations that are similar to such provisions of
the Internal Revenue Code or ERISA (collectively, Similar
Laws). For these purposes the term employee benefit
plan includes, but is not limited to, qualified pension,
profit-sharing and stock bonus plans, Keogh plans, simplified
employee pension plans and tax deferred annuities or individual
retirement accounts or annuities (IRAs) established
or maintained by an employer or employee organization, and
entities whose underlying assets are considered to include
plan assets of such plans, accounts and
arrangements. Among other things, consideration should be given
to:
|
|
|
|
|
whether the investment is prudent under
Section 404(a)(1)(B) of ERISA and any other applicable
Similar Laws;
|
|
|
|
whether in making the investment, the plan will satisfy the
diversification requirements of Section 404(a)(1)(C) of
ERISA and any other applicable Similar Laws;
|
|
|
|
whether the investment will result in recognition of unrelated
business taxable income by the plan and, if so, the potential
after-tax investment return. Please read Material Tax
Consequences Tax-Exempt Organizations and Other
Investors; and
|
|
|
|
whether making such an investment will comply with the
delegation of control and prohibited transaction provisions of
ERISA, the Internal Revenue Code and any other applicable
Similar Laws.
|
The person with investment discretion with respect to the assets
of an employee benefit plan, often called a fiduciary, should
determine whether an investment in us is authorized by the
appropriate governing instrument and is a proper investment for
the plan.
Section 406 of ERISA and Section 4975 of the Internal
Revenue Code prohibit employee benefit plans, and IRAs that are
not considered part of an employee benefit plan, from engaging
in specified transactions involving plan assets with
parties that, with respect to the plan, are parties in
interest under ERISA or disqualified persons
under the Internal Revenue Code unless an exemption is
available. A party in interest or disqualified person who
engages in a non-exempt prohibited transaction may be subject to
excise taxes and other penalties and liabilities under ERISA and
the Internal Revenue Code. In addition, the fiduciary of the
ERISA plan that engaged in such a non-exempt prohibited
transaction may be subject to penalties and liabilities under
ERISA and the Internal Revenue Code.
In addition to considering whether the purchase of common units
is a prohibited transaction, a fiduciary should consider whether
the plan will, by investing in us, be deemed to own an undivided
interest in our assets, with the result that our general partner
would also be a fiduciary of such plan and our operations would
be subject to the regulatory restrictions of ERISA, including
its prohibited transaction rules, as well as the prohibited
transaction rules of the Internal Revenue Code, ERISA and any
other applicable Similar Laws.
The Department of Labor regulations provide guidance with
respect to whether, in certain circumstances, the assets of an
entity in which employee benefit plans acquire equity interests
would be deemed plan assets. Under these
regulations, an entitys assets would not be considered to
be plan assets if, among other things:
|
|
|
|
|
the equity interests acquired by the employee benefit plan are
publicly offered securities i.e., the equity
interests are widely held by 100 or more investors independent
of the issuer and each other, are freely transferable and are
registered under certain provisions of the federal securities
laws;
|
|
|
|
the entity is an operating company,
i.e., it is primarily engaged in the production or sale of a
product or service, other than the investment of capital, either
directly or through a majority-owned subsidiary or
subsidiaries; or
|
214
|
|
|
|
|
there is no significant investment by benefit plan investors,
which is defined to mean that less than 25% of the value of each
class of equity interest is held by the employee benefit plans
referred to above that are subject to ERISA and IRAs and other
similar vehicles that are subject to Section 4975 of the
Internal Revenue Code.
|
Our assets should not be considered plan assets
under these regulations because it is expected that the
investment will satisfy the requirements in the first two bullet
points above.
In light of the serious penalties imposed on persons who engage
in prohibited transactions or other violations, plan fiduciaries
contemplating a purchase of common units should consult with
their own counsel regarding the consequences under ERISA, the
Internal Revenue Code and other Similar Laws.
215
UNDERWRITING
Citigroup Global Markets Inc., Raymond James &
Associates, Inc. and Wells Fargo Securities, LLC are acting as
joint book-running managers of the offering and as
representatives of the underwriters named below. Subject to the
terms and conditions stated in the underwriting agreement dated
the date of this prospectus, each underwriter named below has
severally agreed to purchase, and we have agreed to sell to that
underwriter, the number of common units set forth opposite the
underwriters name.
|
|
|
|
|
|
|
Number of
|
|
Underwriter
|
|
Common Units
|
|
|
Citigroup Global Markets Inc.
|
|
|
|
|
Raymond James & Associates, Inc.
|
|
|
|
|
Wells Fargo Securities, LLC
|
|
|
|
|
J.P. Morgan Securities LLC
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
The underwriting agreement provides that the obligations of the
underwriters to purchase the common units included in this
offering are subject to approval of legal matters by counsel and
to other conditions. The underwriters are obligated to purchase
all the common units (other than those covered by the
underwriters option to purchase additional common units
described below) if they purchase any of the common units.
Common units sold by the underwriters to the public will
initially be offered at the initial public offering price set
forth on the cover of this prospectus. Any common units sold by
the underwriters to securities dealers may be sold at a discount
from the initial public offering price not to exceed
$ per common unit. After the
common units are released for sale to the public, if all the
common units are not sold at the initial public offering price
following a bona fide effort to do so, the underwriters may
change the offering price and the other selling terms. The
representatives have advised us that the underwriters do not
intend to make sales to discretionary accounts.
If the underwriters sell more common units than the total number
set forth in the table above, we have granted to the
underwriters an option, exercisable for 30 days from the
date of this prospectus, to purchase up
to
additional common units at the public offering price less the
underwriting discount. The underwriters may exercise the option
solely for the purpose of covering over-allotments, if any, in
connection with this offering. To the extent the option is
exercised, each underwriter must purchase a number of additional
common units approximately proportionate to that
underwriters initial purchase commitment. Any common units
issued or sold under the option will be issued and sold on the
same terms and conditions as the other common units that are the
subject of this offering.
We, our general partner, certain of our general partners
officers and directors, certain of our affiliates, and certain
of their officers and directors have agreed that, for a period
of 180 days from the date of this prospectus, we and they
will not, without the prior written consent of Citigroup Global
Markets Inc., offer, pledge, sell, contract to sell, sell any
option or contract to purchase, purchase any option or contract
to sell, grant any option, right or warrant to purchase, lend or
otherwise transfer or dispose of, directly or indirectly, any
common units or any securities convertible into or exercisable
or exchangeable for common units, or enter into any swap or
other arrangement that transfers to another, in whole or in
part, any of the economic consequences of ownership of the
common units, whether any such transaction described above is to
be settled by delivery of common units or such other securities,
in cash or otherwise.
Citigroup Global Markets Inc., in its sole discretion, may
release any of the securities subject to these
lock-up
agreements at any time without notice. Notwithstanding the
foregoing, if (i) during the last 17 days of the
180-day
restricted period, we issue an earnings release or material news
or a material event relating to our company occurs; or
(ii) prior to the expiration of the
180-day
restricted period, we announce that we will release earnings
results during the
16-day
period beginning on the last day of the
180-day
restricted period, the restrictions described above shall
continue to apply until the expiration of the
18-day
period beginning on the issuance of the earnings release or the
occurrence of the material news or material event. Citigroup
Global
216
Markets Inc. does not have any present intention or any
understandings, implicit or explicit, to release any of the
common units or other securities subject to the
lock-up
agreements prior to the expiration of the
lock-up
period described above.
At our
request, has
established a Directed Unit Program under which they have
reserved up to common units offered hereby at the public
offering price for officers, directors, employees and certain
other persons associated with us. The number of common units
available for sale to the general public will be reduced to the
extent such persons purchase common units reserved under the
Directed Unit Program. Any reserved common units not so
purchased will be offered by the underwriters to the general
public on the same basis as the other common units offered
hereby. Any participants in this program shall be prohibited
from selling, pledging or assigning any units sold to them
pursuant to this program for a period of 180 days after the
date of this prospectus. This
180-day
period shall be extended with respect to our issuance of an
earnings release or if material news or a material event
relating to us occurs, in the same manner as described above.
Prior to this offering, there has been no public market for our
common units. Consequently, the initial public offering price
for the common units was determined by negotiations between us
and the representative. Among the factors considered in
determining the initial public offering price were our results
of operations, our current financial condition, our future
prospects, our markets, the economic conditions in and future
prospects for the industry in which we compete, our management,
and currently prevailing general conditions in the equity
securities markets, including current market valuations of
publicly traded companies considered comparable to our company.
We cannot assure you, however, that the price at which the
common units will sell in the public market after this offering
will not be lower than the initial public offering price or that
an active trading market in our common units will develop and
continue after this offering.
We intend to apply to list our common units on NASDAQ under the
symbol MEMP. The underwriters have undertaken to
sell the minimum number of common units to the minimum number of
beneficial owners necessary to meet NASDAQ distribution
requirements for trading.
The following table shows the underwriting discount that we are
to pay to the underwriters in connection with this offering.
These amounts are shown assuming both no exercise and full
exercise of the underwriters option to purchase additional
common units.
|
|
|
|
|
|
|
|
|
|
|
Paid by Memorial Production Partners LP
|
|
|
No Exercise
|
|
Full Exercise
|
|
Per common unit
|
|
$
|
|
|
|
$
|
|
|
Total
|
|
$
|
|
|
|
$
|
|
|
We will pay Citigroup Global Markets Inc. a structuring fee
equal
to %
of the gross proceeds of this offering for the evaluation,
analysis and structuring of our partnership.
In connection with this offering, the underwriters may purchase
and sell common units in the open market. Purchases and sales in
the open market may include short sales, purchases to cover
short positions, which may include purchases pursuant to the
underwriters option to purchase additional common units,
and stabilizing purchases.
|
|
|
|
|
Short sales involve secondary market sales by the underwriters
of a greater number of common units than they are required to
purchase in this offering.
|
|
|
|
|
|
Covered short sales are sales of common units in an
amount up to the number of common units represented by the
underwriters option to purchase additional common units.
|
|
|
|
Naked short sales are sales of common units in an
amount in excess of the number of common units represented by
the underwriters option to purchase additional common
units.
|
|
|
|
|
|
Covering transactions involve purchases of common units either
pursuant to the underwriters option to purchase additional
common units or in the open market after the distribution has
been completed in order to cover short positions.
|
217
|
|
|
|
|
To close a naked short position, the underwriters must purchase
common units in the open market after the distribution has been
completed. A naked short position is more likely to be created
if the underwriters are concerned that there may be downward
pressure on the price of the common units in the open market
after pricing that could adversely affect investors who purchase
in this offering.
|
|
|
|
To close a covered short position, the underwriters must
purchase common units in the open market after the distribution
has been completed or must exercise the underwriters
option to purchase additional common units. In determining the
source of common units to close the covered short position, the
underwriters will consider, among other things, the price of
common units available for purchase in the open market as
compared to the price at which they may purchase common units
through the underwriters option to purchase additional
common units.
|
|
|
|
|
|
Stabilizing transactions involve bids to purchase common units
so long as the stabilizing bids do not exceed a specified
maximum.
|
Purchases to cover short positions and stabilizing purchases, as
well as other purchases by the underwriters for their own
accounts, may have the effect of preventing or retarding a
decline in the market price of the common units. They may also
cause the price of the common units to be higher than the price
that would otherwise exist in the open market in the absence of
these transactions. The underwriters may conduct these
transactions on NASDAQ, in the
over-the-counter
market or otherwise. If the underwriters commence any of these
transactions, they may discontinue them at any time.
We estimate that the expenses of the offering, not including the
underwriting discount and structuring fee, will be approximately
$ million, all of which will
be paid by us. The underwriters have agreed to reimburse us for
a portion of the estimated expenses in an amount equal
to % of the gross proceeds of the
offering.
If you purchase common units offered in this prospectus, you may
be required to pay stamp taxes and other charges under the laws
and practices of the country of purchase, in addition to the
offering price listed on the cover page of this prospectus.
Certain of the underwriters and their affiliates have engaged,
and may in the future engage, in commercial banking, investment
banking and advisory services for us, Memorial Resource and our
respective affiliates from time to time in the ordinary course
of their business for which they have received customary fees
and reimbursement of expenses. Affiliates of each of the
underwriters will be lenders under our new revolving credit
facility and will receive a portion of the net proceeds from any
exercise of the underwriters option to purchase additional
units. In addition, an affiliate of Wells Fargo Securities, LLC
is a lender under each of BlueStones and WHT Energy
Partners LLCs credit facilities, which we expect to be
repaid in connection with the closing of this offering. Other
than the participation as lenders under our new revolving credit
facility, none of the underwriters has provided or will provide
financing, investment or advisory services to us during the
180-day
period prior to or the
90-day
period following the date of this prospectus.
The underwriters and their respective affiliates are full
service financial institutions engaged in various activities,
which may include securities trading, commercial and investment
banking, financial advisory, investment management, principal
investment, hedging, financing and brokerage activities. In the
ordinary course of their various business activities, the
underwriters and their respective affiliates may make or hold a
broad array of investments and actively trade debt and equity
securities (or related derivative securities) and financial
instruments (including bank loans) for their own account and for
the accounts of their customers and may at any time hold long
and short positions in such securities and instruments. Such
investment and securities activities may involve securities and
instruments of the issuer.
Because the Financial Industry Regulatory Authority, Inc., or
FINRA, views the common units offered hereby as interests in a
direct participation program, there is no conflict of interest
between us and the underwriters under Rule 5121 of the
FINRA Rules and the offering is being made in compliance with
Rule 2310 of the FINRA Rules. Investor suitability with
respect to the common units should be judged similarly to the
suitability with respect to other securities that are listed for
trading on a national securities exchange.
218
We, our general partner and certain of our affiliates have
agreed to indemnify the underwriters against certain
liabilities, including liabilities under the Securities Act, or
to contribute to payments the underwriters may be required to
make because of any of those liabilities.
Notice to
Prospective Investors in the European Economic Area
In relation to each member state of the European Economic Area
that has implemented the Prospectus Directive (each, a relevant
member state), other than Germany, with effect from and
including the date on which the Prospectus Directive is
implemented in that relevant member state (the relevant
implementation date), an offer of securities described in this
prospectus may not be made to the public in that relevant member
state other than:
|
|
|
|
|
to any legal entity which is a qualified investor as defined in
the Prospectus Directive;
|
|
|
|
to fewer than 100 or, if the Relevant Member State has
implemented the relevant provision of the 2010 PD Amending
Directive, 150, natural or legal persons (other than qualified
investors as defined in the Prospectus Directive), as permitted
under the Prospectus Directive, subject to obtaining the prior
consent of the relevant Dealer or Dealers nominated by the
Issuer for any such offer; or
|
|
|
|
in any other circumstances falling within Article 3(2) of
the Prospectus Directive.
|
provided that no such offer of securities shall require us or
any underwriter to publish a prospectus pursuant to
Article 3 of the Prospectus Directive.
For purposes of this provision, the expression an offer of
securities to the public in any relevant member state
means the communication in any form and by any means of
sufficient information on the terms of the offer and the
securities to be offered so as to enable an investor to decide
to purchase or subscribe for the securities, as the expression
may be varied in that member state by any measure implementing
the Prospectus Directive in that member state, and the
expression Prospectus Directive means Directive
2003/71/EC
(and amendments thereto, including the 2010 PD Amending
Directive, to the extent implemented in the Relevant Member
State), and includes any relevant implementing measure in the
Relevant Member State, and includes any relevant implementing
measure in each relevant member state. The expression 2010 PD
Amending Directive means Directive 2010/73/EU.
We have not authorized and do not authorize the making of any
offer of securities through any financial intermediary on their
behalf, other than offers made by the underwriters with a view
to the final placement of the securities as contemplated in this
prospectus. Accordingly, no purchaser of the securities, other
than the underwriters, is authorized to make any further offer
of the securities on behalf of us or the underwriters.
Notice to
Prospective Investors in the United Kingdom
We may constitute a collective investment scheme as
defined by section 235 of the Financial Services and
Markets Act 2000 (FSMA) that is not a
recognised collective investment scheme for the
purposes of FSMA (CIS) and that has not been
authorised or otherwise approved. As an unregulated scheme, it
cannot be marketed in the United Kingdom to the general public,
except in accordance with FSMA. This prospectus is only being
distributed in the United Kingdom to, and is only directed at:
(i) if we are a CIS and are marketed by a person who is an
authorised person under FSMA, (a) investment professionals
falling within Article 14(5) of the Financial Services and
Markets Act 2000 (Promotion of Collective Investment Schemes)
Order 2001, as amended (the CIS Promotion Order) or
(b) high net worth companies and other persons falling
within Article 22(2)(a) to (d) of the CIS Promotion
Order; or
(ii) otherwise, if marketed by a person who is not an
authorised person under FSMA, (a) persons who fall within
Article 19(5) of the Financial Services and Markets Act
2000 (Financial Promotion) Order 2005, as amended (the
Financial Promotion Order) or (b) Article
49(2)(a) to (d) of the Financial Promotion Order; and
219
(iii) in both cases (i) and (ii) to any other
person to whom it may otherwise lawfully be made, (all such
persons together being referred to as relevant
persons). The common units are only available to, and any
invitation, offer or agreement to subscribe, purchase or
otherwise acquire such common units will be engaged in only
with, relevant persons. Any person who is not a relevant person
should not act or rely on this prospectus or any of its contents.
An invitation or inducement to engage in investment activity
(within the meaning of Section 21 of FSMA) in connection
with the issue or sale of any common units which are the subject
of the offering contemplated by this prospectus will only be
communicated or caused to be communicated in circumstances in
which Section 21(1) of FSMA does not apply to us.
Notice to
Prospective Investors in Germany
This prospectus has not been prepared in accordance with the
requirements for a securities or sales prospectus under the
German Securities Prospectus Act
(Wertpapierprospektgesetz), the German Sales Prospectus
Act (Verkaufsprospektgesetz), or the German Investment
Act (Investmentgesetz). Neither the German Federal
Financial Services Supervisory Authority (Bundesanstalt
für Finanzdienstleistungsaufsicht BaFin)
nor any other German authority has been notified of the
intention to distribute the common units in Germany.
Consequently, the common units may not be distributed in Germany
by way of public offering, public advertisement or in any
similar manner and this prospectus and any other document
relating to this offering, as well as information or statements
contained therein, may not be supplied to the public in Germany
or used in connection with any offer for subscription of the
common units to the public in Germany or any other means of
public marketing. The common units are being offered and sold in
Germany only to qualified investors which are referred to in
Section 3, paragraph 2 no. 1, in connection with
Section 2, no. 6, of the German Securities Prospectus
Act, Section 8f paragraph 2 no. 4 of the German
Sales Prospectus Act, and in Section 2 paragraph 11
sentence 2 no. 1 of the German Investment Act. This
prospectus is strictly for use of the person who has received
it. It may not be forwarded to other persons or published in
Germany.
This offering of our common units does not constitute an offer
to buy or the solicitation or an offer to sell the common units
in any circumstances in which such offer or solicitation is
unlawful.
Notice to
Prospective Investors in the Netherlands
The common units may not be offered or sold, directly or
indirectly, in the Netherlands, other than to qualified
investors (gekwalificeerde beleggers) within the meaning
of Article 1:1 of the Dutch Financial Supervision Act
(Wet op het financieel toezicht).
Notice to
Prospective Investors in Switzerland
This prospectus is being communicated in Switzerland to a small
number of selected investors only. Each copy of this prospectus
is addressed to a specifically named recipient and may not be
copied, reproduced, distributed or passed on to third parties.
The common units are not being offered to the public in
Switzerland, and neither this prospectus, nor any other offering
materials relating to the common units may be distributed in
connection with any such public offering.
We have not been registered with the Swiss Financial Market
Supervisory Authority FINMA as a foreign collective investment
scheme pursuant to Article 120 of the Collective Investment
Schemes Act of June 23, 2006 (CISA).
Accordingly, the common units may not be offered to the public
in or from Switzerland, and neither this prospectus, nor any
other offering materials relating to the common units may be
made available through a public offering in or from Switzerland.
The common units may only be offered and this prospectus may
only be distributed in or from Switzerland by way of private
placement exclusively to qualified investors (as this term is
defined in the CISA and its implementing ordinance).
220
VALIDITY
OF THE COMMON UNITS
The validity of the common units will be passed upon for us by
Akin Gump Strauss Hauer & Feld LLP, Houston, Texas.
Certain legal matters in connection with the common units
offered by us will be passed upon for the underwriters by
Vinson & Elkins L.L.P., Houston, Texas.
EXPERTS
The financial statement of Memorial Production Partners LP as of
April 27, 2011 has been included herein in reliance upon
the report of KPMG LLP, independent registered public accounting
firm, appearing elsewhere herein, and upon the authority of said
firm as experts in accounting and auditing.
The combined financial statements of Memorial Production
Partners LP Predecessor (as described in Note 1 to those
financial statements) as of December 31, 2010 and 2009, and
for each of the years in the three-year period ended
December 31, 2010, have been included herein in reliance
upon the report of KPMG LLP, independent registered public
accounting firm, appearing elsewhere herein, and upon the
authority of said firm as experts in accounting and auditing.
The statements of revenues and direct operating expenses of the
natural gas and oil properties acquired from Forest Oil
Corporation for the years ended December 31, 2009 and 2008
have been included herein in reliance upon the report of KPMG
LLP, independent registered public accounting firm, appearing
elsewhere herein, and upon the authority of said firm as experts
in accounting and auditing.
The statements of revenues and direct operating expenses of the
oil and gas properties acquired by BlueStone Natural Resources,
LLC from BP America Production Company for the three years in
the period ended December 31, 2010 have been included
herein in reliance upon the report of Ernst & Young
LLP, independent auditors, appearing elsewhere herein, and upon
the authority of said firm as experts in auditing and accounting.
Estimated quantities of our proved oil and natural gas reserves
and the net present value of such reserves as of
December 31, 2010 and January 1, 2011 set forth in
this prospectus are based upon reserve reports prepared by us
and audited by Netherland, Sewell & Associates, Inc.
and upon reserve reports prepared by each of Miller and Lents,
Ltd. and Netherland, Sewell & Associates, Inc.
WHERE YOU
CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on
Form S-l
regarding the units. This prospectus does not contain all of the
information found in the registration statement. For further
information regarding us and the common units offered by this
prospectus, you may desire to review the full registration
statement, including its exhibits, filed under the Securities
Act. The registration statement of which this prospectus forms a
part, including its exhibits, may be inspected and copied at the
public reference room maintained by the SEC at
100 F Street, N.E., Washington, D.C. 20549.
Copies of the materials may also be obtained from the SEC at
prescribed rates by writing to the public reference room
maintained by the SEC at 100 F Street, N.E.,
Washington, D.C. 20549. You may obtain information on the
operation of the public reference room by calling the SEC at
1-800-SEC-0330.
The SEC maintains a web site on the Internet at
http://www.sec.gov.
The registration statement, of which this prospectus forms a
part, can be downloaded from the SECs web site.
We intend to furnish our unitholders annual reports containing
our audited financial statements and furnish or make available
quarterly reports containing our unaudited interim financial
information for the first three fiscal quarters of each of our
fiscal years. Additionally, we intend to file periodic reports
with the SEC, as required by the Securities Exchange Act of 1934.
221
FORWARD-LOOKING
STATEMENTS
This prospectus contains forward-looking statements that are
subject to a number of risks and uncertainties, many of which
are beyond our control, which may include statements about our:
|
|
|
|
|
business strategies;
|
|
|
|
ability to replace the reserves we produce through drilling and
property acquisitions;
|
|
|
|
drilling locations;
|
|
|
|
oil and natural gas reserves;
|
|
|
|
technology;
|
|
|
|
realized oil and natural gas prices;
|
|
|
|
production volumes;
|
|
|
|
lease operating expenses;
|
|
|
|
general and administrative expenses;
|
|
|
|
future operating results;
|
|
|
|
cash flows and liquidity;
|
|
|
|
availability of drilling and production equipment;
|
|
|
|
availability of oil field labor;
|
|
|
|
capital expenditures;
|
|
|
|
availability and terms of capital;
|
|
|
|
marketing of oil and natural gas;
|
|
|
|
general economic conditions;
|
|
|
|
competition in the oil and natural gas industry;
|
|
|
|
effectiveness of risk management activities;
|
|
|
|
environmental liabilities;
|
|
|
|
counterparty credit risk;
|
|
|
|
governmental regulation and taxation;
|
|
|
|
developments in oil-producing and natural-gas producing
countries; and
|
|
|
|
plans, objectives, expectations and intentions.
|
These types of statements, other than statements of historical
fact included in this prospectus, are forward-looking
statements. These forward-looking statements may be found in
Summary, Risk Factors, Our Cash
Distribution Policy and Restrictions on Distributions,
Managements Discussion and Analysis of Financial
Condition and Results of Operations, Business and
Properties and other sections of this prospectus. In some
cases, you can identify forward-looking statements by
terminology such as may, will,
could, should, expect,
plan, project, intend,
anticipate, believe,
estimate, predict,
potential, pursue, target,
continue, the negative of such terms or other
comparable terminology.
222
The forward-looking statements contained in this prospectus are
largely based on our expectations, which reflect estimates and
assumptions made by our management. These estimates and
assumptions reflect our best judgment based on currently known
market conditions and other factors. Although we believe such
estimates and assumptions to be reasonable, they are inherently
uncertain and involve a number of risks and uncertainties that
are beyond our control. In addition, managements
assumptions about future events may prove to be inaccurate. All
readers are cautioned that the forward-looking statements
contained in this prospectus are not guarantees of future
performance, and we cannot assure any reader that such
statements will be realized or that the forward-looking events
and circumstances will occur. Actual results may differ
materially from those anticipated or implied in the
forward-looking statements due to factors described in
Risk Factors and elsewhere in this prospectus. All
forward-looking statements speak only as of the date of this
prospectus. We do not intend to update or revise any
forward-looking statements as a result of new information,
future events or otherwise. These cautionary statements qualify
all forward-looking statements attributable to us or persons
acting on our behalf.
223
INDEX TO
FINANCIAL STATEMENTS
|
|
|
|
|
|
|
|
|
|
Unaudited Pro Forma Combined Financial Statements:
|
|
|
|
|
|
|
|
F-2
|
|
|
|
|
F-4
|
|
|
|
|
F-5
|
|
|
|
|
F-6
|
|
|
|
|
F-7
|
|
Historical Balance Sheet:
|
|
|
|
|
|
|
|
F-16
|
|
|
|
|
F-17
|
|
|
|
|
F-18
|
|
|
|
|
|
|
Unaudited Historical Combined Financial Statements as of
March 31, 2011 and December 31, 2010 and for the Three
Months Ended March 31, 2011 and March 31, 2010:
|
|
|
|
|
|
|
|
F-19
|
|
|
|
|
F-20
|
|
|
|
|
F-21
|
|
|
|
|
F-22
|
|
|
|
|
F-23
|
|
Historical Combined Financial Statements as of December 31,
2010 and 2009 and for the Years Ended December 31, 2010,
2009 and 2008:
|
|
|
|
|
|
|
|
F-38
|
|
|
|
|
F-39
|
|
|
|
|
F-40
|
|
|
|
|
F-41
|
|
|
|
|
F-42
|
|
|
|
|
F-43
|
|
FOREST ACQUISITION FINANCIAL STATEMENTS
|
|
|
|
|
Historical Statements of Revenues and Direct Operating Expenses
for the years ended December 31, 2009 and 2008 and for the
Six Months Ended June 30, 2010 (unaudited):
|
|
|
|
|
|
|
|
F-65
|
|
|
|
|
F-66
|
|
|
|
|
F-67
|
|
BP ACQUISITION FINANCIAL STATEMENTS
|
|
|
|
|
Historical Statements of Revenues and Direct Operating Expenses
for each of the three years in the period ended
December 31, 2010, and the Three Months Ended
March 31, 2011 and March 31, 2010 (unaudited):
|
|
|
|
|
|
|
|
F-72
|
|
|
|
|
F-73
|
|
|
|
|
F-74
|
|
F-1
MEMORIAL
PRODUCTION PARTNERS LP
UNAUDITED
PRO FORMA COMBINED FINANCIAL STATEMENTS
Introduction
Memorial Production Partners LP (the Partnership) is
a Delaware limited partnership formed in April 2011 by Memorial
Resource Development LLC (Memorial Resource) to own
and acquire oil and natural gas properties in North America.
Currently, Memorial Resource, a privately held limited liability
company, owns, directly or indirectly, all of the general and
limited partner interests in the Partnership. The following
unaudited pro forma combined financial statements of the
Partnership reflect the audited and unaudited results of
BlueStone Natural Resources, LLC and certain oil and natural gas
properties and related assets of Classic Hydrocarbons Holdings,
L.P. (collectively, the Predecessor) on a pro forma
basis to give effect to (1) certain assets acquired by the
Predecessor after March 31, 2011, and (2) the
Contribution and the Offering described below.
The Predecessors properties that will be acquired by us in
the Contribution include the following:
|
|
|
|
|
oil and natural gas properties and related assets acquired by
the Predecessor from Forest Oil Corporation (Forest
Oil) on June 30, 2010;
|
|
|
|
oil and natural gas properties and related assets acquired by
the Predecessor from BP America Production Company
(BP) on May 31, 2011; and
|
|
|
|
40% of the oil and natural gas properties and related assets
acquired by WHT Energy Partners LLC (WHT), a
subsidiary of Memorial Resource, from a third party on
April 8, 2011 (the Carthage Properties).
|
For periods after April 8, 2011, the Carthage Properties
will be included in our Predecessor.
The Contribution. Effective upon the
closing of the initial public offering of common units of the
Partnership, the Partnership will acquire, for a combination of
cash and newly-issued common units and subordinated units,
(i) substantially all of the oil and natural gas properties
and related assets currently owned by BlueStone Natural
Resources, LLC, a majority-owned subsidiary of Memorial
Resource, (ii) certain oil and natural gas properties and
related assets currently owned by Classic Hydrocarbons Holdings,
L.P., a majority-owned subsidiary of Memorial Resource, and
(iii) certain oil and natural gas properties and related
assets currently owned by WHT, which is 50% owned by WildHorse
Resources, LLC and 50% owned by Tanos Energy, LLC, both of which
are majority-owned subsidiaries of Memorial Resource
(collectively, the Contribution).
The Offering. For purposes of the
unaudited pro forma combined financial statements, the Offering
is defined as the issuance and sale to the public
of
common units of the Partnership contemplated by this prospectus,
the borrowing of $130 million by the Partnership under a
new revolving credit facility, and the application by the
Partnership of the net proceeds from such issuance and borrowing
as described in Use of Proceeds (collectively, the
Offering). We have assumed that net proceeds from
the sale of the common units will be
$ million (based on the
midpoint of the offering price range set forth on the cover of
the prospectus). If the net proceeds from this offering increase
or decrease, then our borrowing under our new revolving credit
facility would correspondingly decrease or increase,
respectively.
The unaudited pro forma combined balance sheet of the
Partnership is based on the unaudited historical combined
balance sheet of the Predecessor as of March 31, 2011 and
includes pro forma adjustments to give effect to the
Contribution and the Offering as if they had occurred on
March 31, 2011.
The unaudited pro forma combined statements of operations of the
Partnership are based on (i) the unaudited historical
combined statements of operations of the Predecessor for the
three months ended March 31, 2011 and the audited
historical combined statement of operations of the Predecessor
for the year
F-2
ended December 31, 2010, each period having been adjusted
to give effect to the Contribution and the Offering as if they
occurred on January 1, 2010, and (iii) the historical
statements of revenues and direct operating expenses of certain
natural gas and oil properties acquired from Forest Oil and BP
and the Carthage Properties included elsewhere in this
registration statement.
The unaudited pro forma combined financial statements have been
prepared on the basis that the Partnership will be treated as a
partnership for federal income tax purposes. The unaudited pro
forma combined financial statements should be read in
conjunction with the notes thereto and with the audited
historical combined financial statements and related notes of
the Predecessor, as well as the other historical statements of
revenues and direct operating expenses, included elsewhere in
this prospectus.
The pro forma adjustments to the unaudited and audited
historical combined financial statements are based on currently
available information and certain estimates and assumptions. The
actual effect of the transactions discussed in the accompanying
notes ultimately may differ from the unaudited pro forma
adjustments included herein. However, management believes that
the assumptions utilized to prepare the pro forma adjustments
provide a reasonable basis for presenting the significant
effects of the transactions as currently contemplated and that
the unaudited pro forma adjustments are factually supportable,
give appropriate effect to the expected impact of events that
are directly attributable to the transactions, and reflect those
items expected to have a continuing impact on the Partnership.
The unaudited pro forma combined financial statements of the
Partnership are not necessarily indicative of the results that
actually would have occurred if the Partnership had completed
the Contribution or the Offering on the dates indicated or which
could be achieved in the future because they necessarily exclude
various operating expenses.
F-3
MEMORIAL
PRODUCTION PARTNERS LP
UNAUDITED
PRO FORMA COMBINED BALANCE SHEET AS OF MARCH
31, 2011
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partnership
|
|
|
|
|
|
|
Partnership
|
|
|
Predecessor
|
|
|
Pre-offering
|
|
|
Offering
|
|
|
Pro
|
|
|
|
Predecessor
|
|
|
Properties
|
|
|
Retained
|
|
|
Partnership
|
|
|
Related
|
|
|
Forma as
|
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Operations
|
|
|
Pro Forma
|
|
|
Adjustments
|
|
|
Adjusted
|
|
|
|
|
|
|
(a)
|
|
|
(b)
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
2,130
|
|
|
$
|
|
|
|
$
|
(2,130
|
)
|
|
$
|
|
|
|
$
|
130,000
|
(c)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
250,000
|
(d)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(150,189
|
)(e)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(189,811
|
)(e)
|
|
|
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(40,000
|
)(f)
|
|
|
|
|
Oil and natural gas sales
|
|
|
5,895
|
|
|
|
|
|
|
|
(260
|
)
|
|
|
5,635
|
|
|
|
|
|
|
|
5,635
|
|
Joint interest owners and other
|
|
|
3,848
|
|
|
|
|
|
|
|
(13
|
)
|
|
|
3,835
|
|
|
|
|
|
|
|
3,835
|
|
Short-term derivative instruments
|
|
|
2,694
|
|
|
|
|
|
|
|
|
|
|
|
2,694
|
|
|
|
|
|
|
|
2,694
|
|
Prepaid expenses and other current assets
|
|
|
798
|
|
|
|
|
|
|
|
(12
|
)
|
|
|
786
|
|
|
|
|
|
|
|
786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
15,365
|
|
|
|
|
|
|
|
(2,415
|
)
|
|
|
12,950
|
|
|
|
|
|
|
|
12,950
|
|
Property and equipment, at cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method
|
|
|
321,144
|
|
|
|
202,523
|
|
|
|
(17,725
|
)
|
|
|
505,942
|
|
|
|
|
|
|
|
505,942
|
|
Other
|
|
|
2,781
|
|
|
|
|
|
|
|
(1,106
|
)
|
|
|
1,675
|
|
|
|
|
|
|
|
1,675
|
|
Accumulated depreciation, depletion and impairment
|
|
|
(97,675
|
)
|
|
|
|
|
|
|
8,194
|
|
|
|
(89,481
|
)
|
|
|
|
|
|
|
(89,481
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, net
|
|
|
226,250
|
|
|
|
202,523
|
|
|
|
(10,637
|
)
|
|
|
418,136
|
|
|
|
|
|
|
|
418,136
|
|
Long-term derivative instruments
|
|
|
2,142
|
|
|
|
|
|
|
|
|
|
|
|
2,142
|
|
|
|
|
|
|
|
2,142
|
|
Other long-term assets
|
|
|
1,285
|
|
|
|
|
|
|
|
(61
|
)
|
|
|
1,224
|
|
|
|
1,600
|
(f)
|
|
|
1,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(945
|
)(i)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
245,042
|
|
|
$
|
202,523
|
|
|
$
|
(13,113
|
)
|
|
$
|
434,452
|
|
|
$
|
655
|
|
|
$
|
435,107
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
5,097
|
|
|
$
|
|
|
|
$
|
(240
|
)
|
|
$
|
4,857
|
|
|
$
|
|
|
|
$
|
4,857
|
|
Revenues payable
|
|
|
3,639
|
|
|
|
|
|
|
|
(1,357
|
)
|
|
|
2,282
|
|
|
|
|
|
|
|
2,282
|
|
Accrued liabilities
|
|
|
3,850
|
|
|
|
|
|
|
|
(46
|
)
|
|
|
3,804
|
|
|
|
|
|
|
|
3,804
|
|
Current portion of long-term debt
|
|
|
78
|
|
|
|
|
|
|
|
(6
|
)
|
|
|
72
|
|
|
|
(72
|
)(e)
|
|
|
|
|
Short-term derivative instruments
|
|
|
186
|
|
|
|
|
|
|
|
|
|
|
|
186
|
|
|
|
|
|
|
|
186
|
|
Asset retirement obligations
|
|
|
25
|
|
|
|
478
|
|
|
|
|
|
|
|
503
|
|
|
|
|
|
|
|
503
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
12,875
|
|
|
|
478
|
|
|
|
(1,649
|
)
|
|
|
11,704
|
|
|
|
(72
|
)
|
|
|
11,632
|
|
Long-term debt
|
|
|
112,506
|
|
|
|
84,051
|
|
|
|
(6,818
|
)
|
|
|
189,739
|
|
|
|
130,000
|
(c)
|
|
|
130,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(189,739
|
)(e)
|
|
|
|
|
Deferred tax liabilities
|
|
|
225
|
|
|
|
|
|
|
|
|
|
|
|
225
|
|
|
|
|
|
|
|
225
|
|
Asset retirement obligations
|
|
|
11,073
|
|
|
|
3,953
|
|
|
|
(594
|
)
|
|
|
14,432
|
|
|
|
|
|
|
|
14,432
|
|
Long-term derivative instruments
|
|
|
275
|
|
|
|
|
|
|
|
|
|
|
|
275
|
|
|
|
|
|
|
|
275
|
|
Other long-term liabilities
|
|
|
49
|
|
|
|
|
|
|
|
(49
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
137,003
|
|
|
|
88,482
|
|
|
|
(9,110
|
)
|
|
|
216,375
|
|
|
|
(59,811
|
)
|
|
|
156,564
|
|
Partners capital
|
|
|
108,039
|
|
|
|
114,041
|
|
|
|
(4,003
|
)
|
|
|
218,077
|
|
|
|
250,000
|
(d)
|
|
|
278,543
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(150,189
|
)(e)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(38,400
|
)(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(945
|
)(i)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
245,042
|
|
|
$
|
202,523
|
|
|
$
|
(13,113
|
)
|
|
$
|
434,452
|
|
|
$
|
655
|
|
|
$
|
435,107
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to the unaudited pro forma combined
financial statements.
F-4
MEMORIAL
PRODUCTION PARTNERS LP
UNAUDITED
PRO FORMA COMBINED STATEMENT OF OPERATIONS
FOR
THE YEAR ENDED DECEMBER 31, 2010
(In
thousands, except per unit amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partnership
|
|
|
Predecessor
|
|
|
Pre-Offering
|
|
|
Offering
|
|
|
Partnership
|
|
|
|
Predecessor
|
|
|
Properties
|
|
|
Retained
|
|
|
Partnership
|
|
|
Related
|
|
|
Pro Forma
|
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Operations
|
|
|
Pro Forma
|
|
|
Adjustments
|
|
|
as Adjusted
|
|
|
|
|
|
|
(g)
|
|
|
(b)
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & natural gas sales
|
|
$
|
37,308
|
|
|
$
|
52,234
|
|
|
$
|
(1,780
|
)
|
|
$
|
87,762
|
|
|
$
|
|
|
|
$
|
87,762
|
|
Other income
|
|
|
1,433
|
|
|
|
|
|
|
|
(29
|
)
|
|
|
1,404
|
|
|
|
|
|
|
|
1,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
38,741
|
|
|
|
52,234
|
|
|
|
(1,809
|
)
|
|
|
89,166
|
|
|
|
|
|
|
|
89,166
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
13,974
|
|
|
|
10,280
|
|
|
|
(1,202
|
)
|
|
|
23,052
|
|
|
|
|
|
|
|
23,052
|
|
Exploration
|
|
|
39
|
|
|
|
|
|
|
|
(3
|
)
|
|
|
36
|
|
|
|
|
|
|
|
36
|
|
Production taxes
|
|
|
2,112
|
|
|
|
5,432
|
|
|
|
(157
|
)
|
|
|
7,387
|
|
|
|
|
|
|
|
7,387
|
|
Depreciation, depletion and amortization
|
|
|
20,066
|
|
|
|
16,640
|
|
|
|
(1,934
|
)
|
|
|
34,772
|
|
|
|
|
|
|
|
34,772
|
|
Impairment of proved oil and natural gas properties
|
|
|
11,800
|
|
|
|
|
|
|
|
(2,291
|
)
|
|
|
9,509
|
|
|
|
|
|
|
|
9,509
|
|
General and administrative
|
|
|
6,116
|
|
|
|
|
|
|
|
(297
|
)
|
|
|
5,819
|
|
|
|
|
|
|
|
5,819
|
|
Accretion
|
|
|
663
|
|
|
|
448
|
|
|
|
(39
|
)
|
|
|
1,072
|
|
|
|
|
|
|
|
1,072
|
|
(Gain)/loss on derivative instruments
|
|
|
(10,264
|
)
|
|
|
|
|
|
|
|
|
|
|
(10,264
|
)
|
|
|
|
|
|
|
(10,264
|
)
|
Gain on sale of properties
|
|
|
(1
|
)
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
890
|
|
|
|
|
|
|
|
|
|
|
|
890
|
|
|
|
|
|
|
|
890
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
45,395
|
|
|
|
32,800
|
|
|
|
(5,922
|
)
|
|
|
72,273
|
|
|
|
|
|
|
|
72,273
|
|
Operating (loss) income
|
|
|
(6,654
|
)
|
|
|
19,434
|
|
|
|
4,113
|
|
|
|
16,893
|
|
|
|
|
|
|
|
16,893
|
|
Interest expense
|
|
|
(4,438
|
)
|
|
|
|
|
|
|
294
|
|
|
|
(4,144
|
)
|
|
|
(3,965
|
)(h)
|
|
|
(4,365
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,144
|
(h)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(400
|
)(i)
|
|
|
|
|
Income tax expense
|
|
|
(225
|
)
|
|
|
|
|
|
|
|
|
|
|
(225
|
)
|
|
|
|
|
|
|
(225
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(11,317
|
)
|
|
$
|
19,434
|
|
|
$
|
4,407
|
|
|
$
|
12,524
|
|
|
$
|
(221
|
)
|
|
$
|
12,303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income
|
|
$
|
|
|
Limited partners interest in net income
|
|
$
|
|
|
Net income per limited partner units:
|
|
|
|
|
Common units (basic)
|
|
$
|
|
|
Subordinated units
|
|
$
|
|
|
Common units (diluted)
|
|
$
|
|
|
Weighted limited partner units outstanding:
|
|
|
|
|
Common units (basic)
|
|
$
|
|
|
Subordinated units
|
|
$
|
|
|
Common units (diluted)
|
|
$
|
|
|
See accompanying notes to the unaudited pro forma combined
financial statements.
F-5
MEMORIAL
PRODUCTION PARTNERS LP
UNAUDITED
PRO FORMA COMBINED STATEMENT OF OPERATIONS
FOR
THE THREE MONTHS ENDED MARCH 31, 2011
(In
thousands, except per unit amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partnership
|
|
|
|
|
|
|
Partnership
|
|
|
Predecessor
|
|
|
Pre-Offering
|
|
|
Offering
|
|
|
Pro
|
|
|
|
Predecessor
|
|
|
Properties
|
|
|
Retained
|
|
|
Partnership
|
|
|
Related
|
|
|
Forma as
|
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Operations
|
|
|
Pro Forma
|
|
|
Adjustments
|
|
|
Adjusted
|
|
|
|
|
|
|
(g)
|
|
|
(b)
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & natural gas sales
|
|
$
|
11,641
|
|
|
$
|
9,440
|
|
|
$
|
(433
|
)
|
|
$
|
20,648
|
|
|
$
|
|
|
|
$
|
20,648
|
|
Other income
|
|
|
103
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
99
|
|
|
|
|
|
|
|
99
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
11,744
|
|
|
|
9,440
|
|
|
|
(437
|
)
|
|
|
20,747
|
|
|
|
|
|
|
|
20,747
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
5,170
|
|
|
|
1,843
|
|
|
|
(328
|
)
|
|
|
6,685
|
|
|
|
|
|
|
|
6,685
|
|
Exploration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
|
693
|
|
|
|
1,036
|
|
|
|
(26
|
)
|
|
|
1,703
|
|
|
|
|
|
|
|
1,703
|
|
Depreciation, depletion and amortization
|
|
|
4,450
|
|
|
|
3,052
|
|
|
|
(476
|
)
|
|
|
7,026
|
|
|
|
|
|
|
|
7,026
|
|
Impairment of proved oil and natural gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
1,474
|
|
|
|
|
|
|
|
(75
|
)
|
|
|
1,399
|
|
|
|
|
|
|
|
1,399
|
|
Accretion
|
|
|
210
|
|
|
|
78
|
|
|
|
(12
|
)
|
|
|
276
|
|
|
|
|
|
|
|
276
|
|
(Gain)/loss on derivative instruments
|
|
|
703
|
|
|
|
|
|
|
|
|
|
|
|
703
|
|
|
|
|
|
|
|
703
|
|
Gain on sale of properties
|
|
|
(8
|
)
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
12,692
|
|
|
|
6,009
|
|
|
|
(909
|
)
|
|
|
17,792
|
|
|
|
|
|
|
|
17,792
|
|
Operating (loss) income
|
|
|
(948
|
)
|
|
|
3,431
|
|
|
|
472
|
|
|
|
2,955
|
|
|
|
|
|
|
|
2,955
|
|
Interest expense
|
|
|
(1,035
|
)
|
|
|
|
|
|
|
62
|
|
|
|
(973
|
)
|
|
|
(992
|
)(h)
|
|
|
(1,092
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
973
|
(h)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(100
|
)(i)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,983
|
)
|
|
$
|
3,431
|
|
|
$
|
534
|
|
|
$
|
1,982
|
|
|
$
|
(119
|
)
|
|
$
|
1,863
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partners interest in net income
|
|
$
|
|
|
Limited partners interest in net income
|
|
$
|
|
|
Net income per limited partner units:
|
|
|
|
|
Common units (basic)
|
|
$
|
|
|
Subordinated units
|
|
$
|
|
|
Common units (diluted)
|
|
$
|
|
|
Weighted limited partner units outstanding:
|
|
|
|
|
Common units (basic)
|
|
$
|
|
|
Subordinated units
|
|
$
|
|
|
Common units (diluted)
|
|
$
|
|
|
See accompanying notes to the unaudited pro forma combined
financial statements.
F-6
MEMORIAL
PRODUCTION PARTNERS LP
NOTES TO
UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS
|
|
Note 1
|
Basis of
Presentation, the Offering, and Other Transactions
|
The unaudited pro forma combined balance sheet of Memorial
Production Partners LP (the Partnership) as of
March 31, 2011, is based on the unaudited historical
combined balance sheet of the Predecessor and includes pro forma
adjustments to give effect to the Contribution and the Offering
as if they occurred on March 31, 2011.
The unaudited pro forma combined statements of operations of the
Partnership are based on the unaudited historical combined
statement of operations of the Predecessor for the three months
ended March 31, 2011 and the audited historical combined
statement of operations of the Predecessor for the year ended
December 31, 2010, each period having been adjusted to give
effect to the acquisitions of the Forest Oil, BP and Carthage
Properties described below, and the Contribution and the
Offering, as if they occurred on January 1, 2010.
The Statements of Revenues less Direct Operating Expenses
related to the oil and gas properties acquired from Forest Oil
and BP and the Carthage Properties are reflective of oil and
natural gas properties accumulated through a series of
acquisitions identified below by the Predecessor and WHT.
The unaudited pro forma combined financial statements give
effect to the contribution of certain oil and natural gas
properties and related assets (the Partnership
Properties) at the closing of the Offering, as follows:
|
|
|
|
|
The sale and contribution to the Partnership of oil and natural
gas properties and related assets owned by the Predecessor,
including:
|
|
|
|
|
|
oil and natural gas properties and related assets acquired by
the Predecessor from Forest Oil on June 30, 2010; and
|
|
|
|
|
|
oil and natural gas properties and related assets acquired by
the Predecessor from BP on May 31, 2011;
|
|
|
|
|
|
The sale and contribution to the Partnership of 40% of the
Carthage Properties acquired by the Predecessor through WHT from
a third party on April 8, 2011;
|
|
|
|
The contribution by the Predecessor and WHT to the Partnership
of certain derivative contracts, which will be used to manage
exposure to oil and natural gas price volatility related to the
production from the Partnership Properties;
|
|
|
|
The retention by the Predecessor of certain oil and natural gas
interests and all other assets, liabilities and operations not
sold or contributed to the Partnership;
|
|
|
|
The issuance by the Partnership
of
common units
and
subordinated units and the payment of
$ million in cash as
consideration for the sale and contribution of the properties
noted above; and
|
|
|
|
The contribution to the Partnership by the general partner of
the Partnership of $ in cash and
the issuance
of
general partner units to the general partner in respect of that
contribution.
|
Because the Partnership Properties are currently owned by the
Predecessor, and the Predecessor and WHT are under the common
control of Memorial Resource, the sale and contribution of the
Partnership Properties to the Partnership are accounted for as a
combination of entities under common control, whereby the assets
and liabilities sold and contributed will be recorded based on
the Predecessors historical cost.
The unaudited pro forma combined financial statements give
effect to the Offering as follows:
|
|
|
|
|
The issuance and sale by the Partnership
of
common units to the public in the initial public offering at an
assumed initial public offering price of
$ per unit, resulting in gross
proceeds to the Partnership of $250 million, before
deduction of estimated underwriting discounts, a structuring fee
and estimated offering expenses of
$ million;
|
|
|
|
Borrowings by the Partnership of $130 million under a new
revolving credit facility (if the net proceeds from this
offering increase or decrease, then our borrowing under our new
revolving credit facility would correspondingly decrease or
increase, respectively); and
|
F-7
MEMORIAL
PRODUCTION PARTNERS LP
NOTES TO
UNAUDITED PRO FORMA COMBINED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
The contribution to the Partnership by the general partner of
the Partnership of $ in cash and
the issuance
of
general partner units to the general partner in respect of that
contribution.
|
|
|
Note 2
|
Pro Forma
Adjustments and Assumptions
|
Unaudited
pro forma combined balance sheet
(a) Adjustments to reflect the inclusion in the Partnership
Properties of certain assets not owned by the Predecessor as of
March 31, 2011 to the Partnership, as summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments
|
|
|
Adjustments
|
|
|
|
|
|
|
for Carthage
|
|
|
for BP
|
|
|
Partnership
|
|
|
|
Properties
|
|
|
Properties
|
|
|
Properties
|
|
|
|
Acquisition
|
|
|
Acquisition
|
|
|
Adjustments
|
|
|
|
|
|
|
(1)
|
|
|
(2)
|
|
|
|
(In thousands)
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
|
|
|
|
|
|
|
|
|
|
|
Joint interest owners and other
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid expenses and other current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, at cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method
|
|
|
124,292
|
|
|
|
79,862
|
|
|
|
202,523
|
|
|
|
|
|
|
|
|
(1,631
|
)
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Less accumulated depreciation, depletion and impairment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, net
|
|
|
124,292
|
|
|
|
78,231
|
|
|
|
202,523
|
|
Long-term derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
Other long-term assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
124,292
|
|
|
$
|
78,231
|
|
|
$
|
202,523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities and Partners Capital
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Revenues payable
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
|
|
|
|
478
|
|
|
|
478
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
|
|
|
|
478
|
|
|
|
478
|
|
Long-term debt
|
|
|
71,189
|
|
|
|
12,862
|
|
|
|
84,051
|
|
Deferred tax liability
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
|
|
3,181
|
|
|
|
772
|
|
|
|
3,953
|
|
Long-term derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
Other long-term liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
74,370
|
|
|
|
14,112
|
|
|
|
88,482
|
|
Partners capital
|
|
|
49,922
|
|
|
|
64,119
|
|
|
|
114,041
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
124,292
|
|
|
$
|
78,231
|
|
|
$
|
202,523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
On April 8, 2011, WHT purchased certain oil and natural gas
properties from a third party for approximately
$302.8 million, of which 40% is being sold and contributed
to the Partnership upon closing of the Offering. The
Partnerships share of WHTs purchase price is
allocated to oil and natural |
F-8
MEMORIAL
PRODUCTION PARTNERS LP
NOTES TO
UNAUDITED PRO FORMA COMBINED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
gas properties in the amount of $124.3 million and to a
liability of $3.2 million for the assumption of future
asset retirement obligations. The WHT properties to be sold and
contributed to the Partnership are burdened by approximately
$71.2 million in indebtedness incurred by WHT in connection
with the acquisition of such properties from a third party. A
portion of the cash proceeds paid to WHT by the Partnership in
respect of such sale and contribution will be used to repay such
indebtedness. |
|
(2) |
|
On May 31, 2011, the Predecessor purchased interests in
wells located in Duval, Jim Hogg, McMullen and Webb counties
from BP in exchange for a combination of approximately
$12.9 million in cash and the Predecessors interest
in the Nueces Field of the Eagle Ford Shale, which consisted
primarily of acreage. The preliminary purchase price allocation
based on the fair value of the assets obtained is allocated to
oil and natural gas properties in the amount of
$79.9 million and to a liability of $1.2 million for
the assumption of future asset retirement obligations.
Additionally, the properties exchanged by the Predecessor
related to this transaction in the amount of $1.6 million
are reflected as a reduction in oil and natural gas properties. |
(b) Adjustments to reflect the assets, liabilities,
revenues and expenses that will be retained by the Predecessor,
and thus will not be contributed to the Partnership. The
adjustment applied to the historical basis of each account was
based on either specific identification or an allocation by
percentage of the relative fair value of the oil and natural gas
assets contributed and the relative fair value of the oil and
natural gas properties retained. General and administrative
expenses are allocated based on the well count for the
properties retained by the Predecessor.
(c) Pro forma adjustment to reflect the cash proceeds
related to borrowings by the Partnership of $130 million
under a new revolving credit facility. If the net proceeds from
this offering increase or decrease, then our borrowing under our
new revolving credit facility would correspondingly decrease or
increase, respectively.
(d) Pro forma adjustment to reflect gross cash proceeds of
approximately $250 million from the issuance and sale
of
common units by the Partnership at an assumed initial public
offering price of $ per unit.
(e) Pro forma adjustments to record the use of the $340.0
million of net proceeds from the Offering paid and distributed
to Memorial Resource, shown as follows:
(1) To reflect the use by WHT of $71.2 million in
proceeds to repay indebtedness previously incurred in connection
with the acquisition of the assets sold and contributed by WHT
to the Partnership;
(2) To reflect the use by the Predecessor of
$118.5 million in proceeds to repay indebtedness previously
incurred in connection with the acquisition of certain of the
Partnership Properties by the Predecessor; and
(3) To reflect a $150.2 million cash distribution made
to Memorial Resource.
For further discussion on the application of the net proceeds
from the Offering, please read Use of Proceeds.
(f) Pro forma adjustment to reflect estimated deferred
financing costs of $ million
related to establishment of the new revolving credit facility,
underwriting discounts of
$ million, a structuring fee
of $ and estimated offering expenses of
$ million.
F-9
MEMORIAL
PRODUCTION PARTNERS LP
NOTES TO
UNAUDITED PRO FORMA COMBINED FINANCIAL
STATEMENTS (Continued)
Unaudited
pro forma statements of operations
(g) The adjustments reflect the pro forma revenues and
expenses associated with the Partnership Properties, as
summarized below.
Year
Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forest
|
|
|
Carthage
|
|
|
BP
|
|
|
|
|
|
|
|
|
|
Properties
|
|
|
Properties
|
|
|
Properties
|
|
|
|
|
|
|
|
|
|
Revenues &
|
|
|
Revenues &
|
|
|
Revenues &
|
|
|
Additional
|
|
|
|
|
|
|
Direct
|
|
|
Direct
|
|
|
Direct
|
|
|
Adjustments
|
|
|
Partnership
|
|
|
|
Operating
|
|
|
Operating
|
|
|
Operating
|
|
|
for Property
|
|
|
Properties
|
|
|
|
Expenses
|
|
|
Expenses
|
|
|
Expenses
|
|
|
Acquisitions
|
|
|
Adjustments
|
|
|
|
(6)
|
|
|
(1)
|
|
|
(2)
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & natural gas sales
|
|
$
|
8,668
|
|
|
$
|
64,738
|
|
|
$
|
18,896
|
|
|
$
|
(37,005
|
)(3)
|
|
$
|
52,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,063
|
)(7)
|
|
|
|
|
Other income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
8,668
|
|
|
|
64,738
|
|
|
|
18,896
|
|
|
|
(40,068
|
)
|
|
|
52,234
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
1,975
|
|
|
|
9,830
|
|
|
|
4,373
|
|
|
|
(5,898
|
)(3)
|
|
|
10,280
|
|
Transportation
|
|
|
|
|
|
|
3,063
|
|
|
|
|
|
|
|
(3,063
|
)(7)
|
|
|
|
|
Exploration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
|
882
|
|
|
|
4,799
|
|
|
|
2,630
|
|
|
|
(2,879
|
)(3)
|
|
|
5,432
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,430
|
(6)
|
|
|
16,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,976
|
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,234
|
(5)
|
|
|
|
|
Impairment of proved oil and natural gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
148
|
(6)
|
|
|
448
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
239
|
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61
|
(5)
|
|
|
|
|
(Gain)/loss on derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
2,857
|
|
|
|
17,692
|
|
|
|
7,003
|
|
|
|
5,248
|
|
|
|
32,800
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
|
5,811
|
|
|
|
47,046
|
|
|
|
11,893
|
|
|
|
(45,316
|
)
|
|
|
19,434
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
5,811
|
|
|
$
|
47,046
|
|
|
$
|
11,893
|
|
|
$
|
(45,316
|
)
|
|
$
|
19,434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-10
MEMORIAL
PRODUCTION PARTNERS LP
NOTES TO
UNAUDITED PRO FORMA COMBINED FINANCIAL
STATEMENTS (Continued)
Three
Months Ended March 31, 2011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carthage
|
|
|
BP
|
|
|
|
|
|
|
|
|
|
Properties
|
|
|
Properties
|
|
|
Additional
|
|
|
|
|
|
|
Revenues &
|
|
|
Revenues &
|
|
|
Adjustments
|
|
|
|
|
|
|
Direct
|
|
|
Direct
|
|
|
for
|
|
|
Partnership
|
|
|
|
Operating
|
|
|
Operating
|
|
|
Property
|
|
|
Properties
|
|
|
|
Expenses
|
|
|
Expenses
|
|
|
Acquisitions
|
|
|
Adjustments
|
|
|
|
(1)
|
|
|
(2)
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & natural gas sales
|
|
$
|
15,069
|
|
|
$
|
3,732
|
|
|
$
|
(8,563
|
)(3)
|
|
$
|
9,440
|
|
|
|
|
|
|
|
|
|
|
|
|
(798
|
)(7)
|
|
|
|
|
Other income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
15,069
|
|
|
|
3,732
|
|
|
|
(9,361
|
)
|
|
|
9,440
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
2,124
|
|
|
|
993
|
|
|
|
(1,274
|
)(3)
|
|
|
1,843
|
|
Transportation
|
|
|
798
|
|
|
|
|
|
|
|
(798
|
)(7)
|
|
|
|
|
Exploration
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes
|
|
|
1,142
|
|
|
|
579
|
|
|
|
(685
|
)(3)
|
|
|
1,036
|
|
Depreciation, depletion and amortization
|
|
|
|
|
|
|
|
|
|
|
1,244
|
(4)
|
|
|
3,052
|
|
|
|
|
|
|
|
|
|
|
|
|
1,808
|
(5)
|
|
|
|
|
Impairment of proved oil and natural gas properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion
|
|
|
|
|
|
|
|
|
|
|
62
|
(4)
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
16
|
(5)
|
|
|
|
|
(Gain)/loss on derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of properties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other, net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
4,064
|
|
|
|
1,572
|
|
|
|
373
|
|
|
|
6,009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
|
11,005
|
|
|
|
2,160
|
|
|
|
(9,734
|
)
|
|
|
3,431
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
11,005
|
|
|
$
|
2,160
|
|
|
$
|
(9,734
|
)
|
|
$
|
3,431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Adjustments reflect the pro forma revenues and direct operating
expenses of the properties acquired by WHT on April 8,
2011, as noted above. Historical lease operating statements by
individual asset were used as the basis for the revenues and
direct operating expenses. |
|
(2) |
|
Adjustments reflect the pro forma revenues and direct operating
expenses of the BP properties acquired by the Predecessor on
May 31, 2011, as noted above. Historical lease operating
statements by individual asset were used as the basis for the
revenues and direct operating expenses. |
|
(3) |
|
Pro forma adjustments to reflect the 60% of the revenues and
direct operating expenses associated with the properties
acquired by WHT on April 8, 2011 that are not being sold
and contributed to the Partnership in the Contribution. These
adjustments are net of the reclassification described in
footnote (7) below. |
|
(4) |
|
Pro forma adjustments to reflect the depletion and depreciation
on property and equipment and the accretion expense on asset
retirement obligations associated with the Carthage Properties,
the Partnerships 40% share of the properties acquired by
WHT on April 8, 2011. |
F-11
MEMORIAL
PRODUCTION PARTNERS LP
NOTES TO
UNAUDITED PRO FORMA COMBINED FINANCIAL
STATEMENTS (Continued)
|
|
|
(5) |
|
Pro forma adjustments to reflect the depletion and depreciation
on property and equipment and the accretion expense on asset
retirement obligations associated with the BP properties
acquired by the Predecessor. |
|
(6) |
|
Pro forma adjustments to reflect the depletion and depreciation
on property and equipment and the accretion expense on asset
retirement obligations for the period January 1, 2010
through June 30, 2010 associated with the Forest Oil
properties acquired by the Predecessor. On June 30, 2010,
the Predecessor purchased certain oil and natural gas properties
from Forest Oil for approximately $65.9 million. The actual
results of the Forest Oil properties acquired are included in
the Predecessors statement of operations for the periods
subsequent to June 30, 2010. Accordingly, the pro forma
combined statement of operations for the year ended
December 31, 2010 is only adjusted for the revenues and
operating expenses of the Forest Oil properties from
January 1, 2010 to June 30, 2010. |
|
(7) |
|
Amounts represent historical transportation and marketing costs
related to the Carthage Properties for the three months ended
March 31, 2011 and the year ended December 31, 2010,
respectively. The seller of the Carthage Properties previously
recorded these amounts within expenses, as they paid such
amounts on a gross basis to a third-party transportation and
marketing company. However, WHT receives a wellhead price from
the third-party purchasers that is net of transportation and
marketing costs, and therefore, records these costs on a net
basis within revenue. As a result, all transportation and
marketing expenses associated with the properties acquired by
WHT on April 8, 2011 have been reclassified from expenses
to within revenue on the pro forma combined statements of
operations to reflect the Partnerships net presentation of
such costs subsequent to the acquisition of the Carthage
Properties but prior to the adjustments shown in
footnote (3) above. |
(h) Pro forma adjustment to reflect the reduction in
interest expense associated with the repayment of Predecessor
debt and to reflect the incurrence of interest expense on
$130 million of borrowings by the Partnership under a new
revolving credit facility at LIBOR plus 2.75%, or 3.05%. If the
net proceeds from the common unit offering increase or decrease
by $10 million, the Partnership would accordingly incur
borrowings under the new credit facility of $120 million or
$140 million, respectively), which would change pro forma
interest expense by $0.3 million for the year ended
December 31, 2010 and $0.1 million for the three
months ended March 31, 2011. A one-eighth percentage point
change in the interest rate would change pro forma interest
expense by $0.2 million for the year ended
December 31, 2010 and less than $0.1 million for the
three months ended March 31, 2011.
(i) Pro forma adjustment to reflect the write-off of
unamortized deferred financing costs (balance sheet) upon
repayment of debt assumed from the Predecessor and the
subsequent amortization of deferred financing costs (statements
of operations) over the Partnerships new revolving credit
facilitys life.
|
|
Note 3
|
Pro Forma
Net Income Per Limited Partner Unit
|
Pro forma net income per limited partner unit is determined by
dividing the pro forma net income available to holders of common
units, after deducting the general partners 0.1% interest
in pro forma net income, by the number of common units and
subordinated units expected to be outstanding at the closing of
the Offering. For purposes of this calculation, we assumed the
aggregate number of common units
was million and subordinated
units
was .
All units were assumed to have been outstanding since
January 1, 2010. Basic and diluted pro forma net income per
unit are equivalent as there will be no dilutive units at the
date of the closing of the Offering of the common units of the
Partnership.
|
|
Note 4
|
Pro Forma
Standardized Measure of Discounted Future Net Cash
Flows
|
Estimated
Quantities of Proved Oil and Natural Gas Reserves
Users of this information should be aware that the process of
estimating quantities of proved and proved
developed oil and natural gas reserves is very complex,
requiring significant subjective decisions in
F-12
MEMORIAL
PRODUCTION PARTNERS LP
NOTES TO
UNAUDITED PRO FORMA COMBINED FINANCIAL
STATEMENTS (Continued)
the evaluation of all available geological, engineering and
economic data for each reservoir. The data for a given reservoir
may also change substantially over time as a result of numerous
factors including, but not limited to, additional activity,
evolving production history and continual reassessment of the
viability of production under varying economic conditions. As a
result, revisions to existing reserve estimates may occur from
time to time. Although every reasonable effort is made to ensure
reserve estimates reported represent the most accurate
assessments possible, the subjective decisions and variances in
available data for various reservoirs make these estimates
generally less precise than other estimates included in the
financial statement disclosures.
Proved reserves represent estimated quantities of natural gas,
crude oil and condensate that geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in
future years from known reservoirs under economic and operating
conditions in effect when the estimates were made. Proved
developed reserves are proved reserves expected to be recovered
through wells and equipment in place and under operating methods
used when the estimates were made.
The following table illustrates the Partnerships pro forma
estimated net proved reserves, including changes in proved
reserves, for the periods indicated. The oil price as of
December 31, 2010, is based on the twelve month unweighted
average of the first of the month prices of the West Texas
Intermediate (Plains) posted price which equates to $75.96 per
barrel. The oil and natural gas liquids prices were adjusted by
lease for quality, transportation fees, and regional price
differentials.
The gas price as of December 31, 2010, is based on the
twelve month unweighted average of the first of the month prices
of the Henry Hub spot price which equates to $4.376 per MMBtu.
All prices are adjusted by lease for quality of energy content,
transportation fees, and regional price differentials. All
prices are held constant in accordance with SEC guidelines. All
proved reserves are located in South and East Texas.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves
|
|
|
|
|
|
|
|
|
Equivalent
|
|
|
Oil (MBbls)
|
|
Gas (MMcf)
|
|
NGL (MBbls)
|
|
(MMcfe)
|
|
Proved reserves, December 31, 2009
|
|
|
1,794
|
|
|
|
196,864
|
|
|
|
4,224
|
|
|
|
232,972
|
|
Extensions and discoveries
|
|
|
60
|
|
|
|
7,603
|
|
|
|
211
|
|
|
|
9,229
|
|
Purchase of minerals in place
|
|
|
259
|
|
|
|
78,046
|
|
|
|
|
|
|
|
79,600
|
|
Production
|
|
|
(107
|
)
|
|
|
(16,713
|
)
|
|
|
(272
|
)
|
|
|
(18,985
|
)
|
Sale of minerals in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revision of previous estimates
|
|
|
(4
|
)
|
|
|
19,876
|
|
|
|
339
|
|
|
|
21,881
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, December 31, 2010
|
|
|
2,002
|
|
|
|
285,676
|
|
|
|
4,502
|
|
|
|
324,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The SEC amended its definitions of oil and natural gas reserves
effective December 31, 2009. Previous periods were not
restated for the new rules. Key revisions include a change in
pricing used to prepare reserve estimates to a twelve month
unweighted average of the
first-day-of-the-month
prices, the inclusion of non-traditional resources in reserves,
definitional changes, and allowing the application of reliable
technologies in determining proved reserves, and other new
disclosures.
The reserves described above have been estimated by management,
using deterministic methods. For wells classified as proved
developed producing where sufficient production history existed,
reserves were based on individual well performance evaluation
and production decline curve extrapolation techniques. For
undeveloped locations and wells that lack sufficient production
history, reserves were based on analogy to producing wells
within the same area exhibiting similar geologic and reservoir
characteristics, combined with volumetric methods. The
volumetric estimates were based on geologic maps and rock and
fluid properties derived from well logs, core data, pressure
measurements, and fluid samples. Well spacing was determined
from drainage patterns derived from a combination of
performance-based recoveries and volumetric estimates
F-13
MEMORIAL
PRODUCTION PARTNERS LP
NOTES TO
UNAUDITED PRO FORMA COMBINED FINANCIAL
STATEMENTS (Continued)
for each area or field. Proved undeveloped locations were
limited to areas of uniformly high quality reservoir properties,
between existing commercial producers.
Standardized
Measure of Discounted Future Net Cash Flows Relating to Oil and
Gas Reserves
The following Standardized Measure of Discounted Future Net Cash
Flow information has been developed utilizing ASC 932,
Extractive Activities Oil and Gas, (ASC932)
procedures and based on oil and natural gas reserve and
production volumes estimated by the Partnerships
engineering staff. It can be used for some comparisons, but
should not be the only method used to evaluate the Partnership
Properties or their performance. Further, the information in the
following table may not represent realistic assessments of
future cash flows, nor should the Standardized Measure of
Discounted future Net Cash Flow be viewed as representative of
the current value of the Partnership Properties.
The Partnership believes that the following factors should be
taken into account when reviewing the following information:
|
|
|
|
|
future costs and selling prices will probably differ from those
required to be used in these calculations;
|
|
|
|
due to future market conditions and governmental regulations,
actual rates of production in future years may vary
significantly from the rate of production assumed in the
calculations;
|
|
|
|
a 10% discount rate may not be reasonable as a measure of the
relative risk inherent in realizing future net oil and natural
revenues; and
|
|
|
|
the effects of federal income taxes have been excluded.
|
Under the Standardized Measure, for the year ended
December 31, 2010 the future cash inflows were estimated by
applying unweighted twelve month average of the first day of the
month cash price quotes to the estimated future production of
period end proved reserves. The resulting net cash flows are
reduced to present value amounts by applying a 10% discount
factor. Use of a 10% discount rate and the unweighted twelve
month average prices were required.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
Predecessor
|
|
Contribution
|
|
Partnership
|
|
Pro Forma
|
|
Pro Forma
|
|
|
Historical
|
|
Adjustments
|
|
Properties
|
|
Adjustments (1)
|
|
Partnership
|
|
Future cash inflows
|
|
$
|
780,477
|
|
|
$
|
750,264
|
|
|
$
|
18,491
|
|
|
$
|
41,345
|
|
|
$
|
1,553,595
|
|
Future production costs
|
|
|
(291,486
|
)
|
|
|
(250,185
|
)
|
|
|
(8,808
|
)
|
|
|
(32,628
|
)
|
|
|
(565,491
|
)
|
Future development costs
|
|
|
(68,046
|
)
|
|
|
(40,321
|
)
|
|
|
(3,686
|
)
|
|
|
|
|
|
|
(104,681
|
)
|
Future income tax expense(2)
|
|
|
(5,463
|
)
|
|
|
(5,252
|
)
|
|
|
(129
|
)
|
|
|
(289
|
)
|
|
|
(10,875
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows before 10% discount
|
|
|
415,482
|
|
|
|
454,506
|
|
|
|
5,868
|
|
|
|
8,428
|
|
|
|
872,548
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(231,667
|
)
|
|
|
(276,336
|
)
|
|
|
(2,540
|
)
|
|
|
(7,887
|
)
|
|
|
(513,350
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
183,815
|
|
|
$
|
178,170
|
|
|
$
|
3,328
|
|
|
$
|
541
|
|
|
$
|
359,198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Consists of revisions to previous estimates of proved reserves
related primarily to oil and gas properties acquired by the
Predecessor from BP in 2011. |
|
(2) |
|
Represents future amounts owed associated with Texas margin tax. |
F-14
MEMORIAL
PRODUCTION PARTNERS LP
NOTES TO
UNAUDITED PRO FORMA COMBINED FINANCIAL
STATEMENTS (Continued)
Changes
in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Natural Gas Reserves
The following tabulation is a summary of changes between the
total standardization measure of discounted future net cash
flows at the beginning and end of 2010:
|
|
|
|
|
|
|
December 31, 2010
|
|
|
(In thousands)
|
|
Beginning of year
|
|
$
|
215,970
|
|
Sale of oil and natural gas produced, net of production costs
|
|
|
(52,623
|
)
|
Purchase of minerals in place
|
|
|
104,729
|
|
Sales of minerals in place
|
|
|
|
|
Extensions and discoveries
|
|
|
8,526
|
|
Changes in income taxes, net
|
|
|
(1,747
|
)
|
Changes in prices and costs
|
|
|
57,481
|
|
Previously estimated development costs incurred
|
|
|
2,229
|
|
Net changes in future development costs
|
|
|
(4,948
|
)
|
Revisions of previous quantities
|
|
|
15,646
|
|
Accretion of discount
|
|
|
21,584
|
|
Changes in production rates and other
|
|
|
(7,649
|
)
|
End of year
|
|
$
|
359,198
|
|
|
|
|
|
|
F-15
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors
Memorial Production Partners GP LLC:
We have audited the accompanying balance sheet of Memorial
Production Partners LP as of April 27, 2011. This financial
statement is the responsibility of the Memorial Production
Partners LPs management. Our responsibility is to express
an opinion on this financial statement based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statement referred to above
presents fairly, in all material respects, the financial
position of Memorial Production Partners LP as of April 27,
2011, in conformity with U.S. generally accepted accounting
principles.
/s/ KPMG LLP
Dallas, TX
June 22, 2011
F-16
|
|
|
|
|
|
|
April 27, 2011
|
|
|
Assets
|
|
|
|
|
Cash
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
|
|
|
|
|
|
|
Partners capital
|
|
|
|
|
Limited partners capital
|
|
|
999
|
|
General partners capital
|
|
|
1
|
|
Receivable from partners
|
|
|
(1,000
|
)
|
|
|
|
|
|
Total partners capital
|
|
$
|
|
|
|
|
|
|
|
See accompanying notes to financial statements.
F-17
MEMORIAL
PRODUCTION PARTNERS LP
NOTE TO BALANCE SHEET
Memorial Production Partners LP (the Partnership) is
a limited partnership formed in April 2011 by Memorial Resource
Development LLC (Memorial Resource) to own and
acquire oil and natural gas properties and related assets of
BlueStone Natural Resources, LLC, a majority-owned subsidiary of
Memorial Resource, certain oil and natural gas properties and
related assets currently owned by Classic Hydrocarbons Holdings,
L.P., a majority-owned subsidiary of Memorial Resource and
certain oil and natural gas properties and related assets
currently owned by WHT Energy Partners LLC, a majority-owned
subsidiary of Memorial Resource. The Partnership intends to
operate the acquired assets through a wholly-owned limited
liability company. In connection with its formation, the
Partnership will issue (a) a 0.1% general partner interest
to Memorial Production Partners GP LLC, its general partner and
(b) a 99.9% limited partner interest to Memorial Resource,
its organizational limited partner. The Partnership plans to
pursue an initial public offering of its common units
representing limited partner interests (the
Offering). Separately, the Partnership will issue to
Memorial Resource subordinated and common units representing
additional limited partner interests, and an aggregate 0.1%
general partner interest to Memorial Production Partners GP LLC.
Memorial Production Partners GP LLC, as general partner, has
committed to contribute $1 and Memorial Resource, as the initial
limited partner, has committed to contribute $999 in the
aggregate to the Partnership as of April 27, 2011. These
contributions receivable are reflected as a reduction to equity
in accordance with generally accepted accounting principles. The
accompanying financial statement reflects the financial position
of the Partnership immediately subsequent to this initial
capitalization. There have been no other transactions involving
the Partnership as of April 27, 2011.
F-18
PREDECESSOR
COMBINED
BALANCE SHEETS AS OF MARCH 31, 2011 AND
DECEMBER 31, 2010
|
|
|
|
|
|
|
|
|
|
|
March 31, 2011
|
|
|
December 31, 2010
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
2,130
|
|
|
$
|
5,654
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
|
5,895
|
|
|
|
6,175
|
|
Joint interest owners and other
|
|
|
3,848
|
|
|
|
3,848
|
|
Short-term derivative instruments
|
|
|
2,694
|
|
|
|
3,791
|
|
Prepaid expenses and other current assets
|
|
|
798
|
|
|
|
771
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
15,365
|
|
|
|
20,239
|
|
Property and equipment, at cost:
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method
|
|
|
321,144
|
|
|
|
314,975
|
|
Other
|
|
|
2,781
|
|
|
|
2,553
|
|
|
|
|
|
|
|
|
|
|
|
|
|
323,925
|
|
|
|
317,528
|
|
Accumulated depreciation, depletion and impairment
|
|
|
(97,675
|
)
|
|
|
(93,224
|
)
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, net
|
|
|
226,250
|
|
|
|
224,304
|
|
Long-term derivative instruments
|
|
|
2,142
|
|
|
|
2,699
|
|
Other long-term assets
|
|
|
1,285
|
|
|
|
1,298
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
245,042
|
|
|
$
|
248,540
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
5,097
|
|
|
$
|
8,482
|
|
Revenues payable
|
|
|
3,639
|
|
|
|
3,564
|
|
Accrued liabilities
|
|
|
3,850
|
|
|
|
3,874
|
|
Current portion of long-term debt
|
|
|
78
|
|
|
|
69
|
|
Short-term derivative instruments
|
|
|
186
|
|
|
|
109
|
|
Asset retirement obligations
|
|
|
25
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
12,875
|
|
|
|
16,123
|
|
Long-term debt
|
|
|
112,506
|
|
|
|
115,359
|
|
Deferred tax liabilities
|
|
|
225
|
|
|
|
225
|
|
Asset retirement obligations
|
|
|
11,073
|
|
|
|
10,867
|
|
Long-term derivative instruments
|
|
|
275
|
|
|
|
109
|
|
Other long-term liabilities
|
|
|
49
|
|
|
|
56
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
137,003
|
|
|
|
142,739
|
|
Commitments and contingencies (Note 10)
|
|
|
|
|
|
|
|
|
Partners capital
|
|
|
108,039
|
|
|
|
105,801
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
245,042
|
|
|
$
|
248,540
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to combined financial statements.
F-19
PREDECESSOR
THREE
MONTHS ENDED MARCH 31, 2011 AND 2010
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil & natural gas sales
|
|
$
|
11,641
|
|
|
$
|
7,879
|
|
Other income
|
|
|
103
|
|
|
|
67
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
11,744
|
|
|
|
7,946
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
5,170
|
|
|
|
2,220
|
|
Production and ad valorem taxes
|
|
|
693
|
|
|
|
509
|
|
Depreciation, depletion and amortization
|
|
|
4,450
|
|
|
|
4,352
|
|
Impairment of proved oil and natural gas properties
|
|
|
|
|
|
|
1,691
|
|
General and administrative
|
|
|
1,474
|
|
|
|
1,108
|
|
Accretion
|
|
|
210
|
|
|
|
64
|
|
(Gain)/loss on derivative instruments
|
|
|
703
|
|
|
|
(6,636)
|
|
Gain on sale of properties
|
|
|
(8)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
12,692
|
|
|
|
3,308
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
|
(948)
|
|
|
|
4,638
|
|
Interest expense
|
|
|
(1,035)
|
|
|
|
(606)
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,983)
|
|
|
$
|
4,032
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to combined financial statements.
F-20
PREDECESSOR
THREE
MONTHS ENDED MARCH 31, 2011
|
|
|
|
|
|
|
Total Partners
|
|
|
|
Capital
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Balance December 31, 2010
|
|
$
|
105,801
|
|
Contributions from partners
|
|
|
4,221
|
|
Distributions to partners
|
|
|
0
|
|
Net income
|
|
|
(1,983
|
)
|
|
|
|
|
|
Balance March 31, 2011
|
|
$
|
108,039
|
|
|
|
|
|
|
See accompanying notes to combined financial statements.
F-21
PREDECESSOR
THREE
MONTHS ENDED MARCH 31, 2011 AND 2010
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,983)
|
|
|
$
|
4,032
|
|
Adjustments to reconcile net (loss) income to net cash provided
by operating activities:
|
|
|
|
|
|
|
|
|
Depreciation, depletion, and amortization
|
|
|
4,450
|
|
|
|
4,352
|
|
Impairment of proved oil and natural gas properties
|
|
|
|
|
|
|
1,691
|
|
Unrealized (gain) loss on derivatives
|
|
|
1,898
|
|
|
|
(5,703)
|
|
Amortization of loan origination fees
|
|
|
85
|
|
|
|
60
|
|
Accretion
|
|
|
210
|
|
|
|
64
|
|
Gain on sale of properties
|
|
|
(8)
|
|
|
|
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
281
|
|
|
|
(1,470)
|
|
Prepaid expenses and other assets
|
|
|
(100)
|
|
|
|
555
|
|
Accounts payable
|
|
|
(1,879)
|
|
|
|
818
|
|
Revenue payable
|
|
|
76
|
|
|
|
(717)
|
|
Accrued liabilities
|
|
|
(25)
|
|
|
|
339
|
|
Other
|
|
|
(6)
|
|
|
|
(86)
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
2,999
|
|
|
$
|
3,935
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
Acquisition of oil and natural gas properties
|
|
|
(1,650)
|
|
|
|
(8,220)
|
|
Additions to oil and gas properties
|
|
|
(6,021)
|
|
|
|
(3,681)
|
|
Additions to other property and equipment
|
|
|
(227)
|
|
|
|
(100)
|
|
Proceeds from the sale of oil and gas properties
|
|
|
|
|
|
|
1,400
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
$
|
(7,898)
|
|
|
$
|
(10,601)
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
Advances on revolving credit facility
|
|
|
47
|
|
|
|
1,289
|
|
Payments on revolving credit facility
|
|
|
(2,893)
|
|
|
|
|
|
Contributed capital
|
|
|
4,221
|
|
|
|
8,145
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
1,375
|
|
|
|
9,434
|
|
Net increase (decrease) in cash
|
|
$
|
(3,524)
|
|
|
$
|
2,768
|
|
Cash and cash equivalents, beginning of period
|
|
$
|
5,654
|
|
|
$
|
5,297
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
2,130
|
|
|
$
|
8,065
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flows:
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
987
|
|
|
$
|
568
|
|
See accompanying notes to combined financial statements.
F-22
PREDECESSOR
General
Memorial Production Partners LP (the Partnership) is
a limited partnership formed in April 2011 by Memorial Resource
Development LLC (Memorial Resource) to acquire,
develop and produce oil and natural gas properties and to
acquire, own and operate related assets. Memorial Resource,
which is owned by Natural Gas Partners VIII, L.P. (NGP
VIII) and Natural Gas Partners IX, L.P., currently owns
all the general and limited partner interests in the
Partnership. The Partnership plans to pursue an initial public
offering of its common units representing limited partner
interests (the Offering). In connection with the
closing of the Offering, pursuant to a planned contribution,
conveyance and assignment agreement, the Partnership will
acquire for a combination of cash and common units
(1) substantially all of the oil and natural gas properties
and related assets currently owned by BlueStone Natural
Resources, LLC, a majority-controlled subsidiary of Memorial
Resource, (2) certain oil and natural gas properties and
related assets currently owned by Classic Hydrocarbons Holdings,
L.P., a majority-controlled subsidiary of Memorial Resource, and
(3) certain oil and natural gas properties and related
assets currently controlled by WHT Energy Partners LLC, which is
50% owned by WildHorse Resources, LLC and 50% owned by Tanos
Energy, LLC, both of which are majority-controlled subsidiaries
of Memorial Resource. The WHT Energy Partners LLC assets were
acquired in April 2011.
The following entities were determined in accordance with the
rules and regulations of the U.S. Securities and Exchange
Commission to represent the combined predecessor (the
Predecessor) of the Partnership.
|
|
|
|
|
BlueStone Natural Resources, LLC (BlueStone) is a
Delaware limited liability company formed in January 2006 to
engage in the acquisition, development, production and
exploration and sale of oil and natural gas. BlueStone is a
wholly owned subsidiary of BlueStone Natural Resources Holdings,
LLC (Holdings), whose sole purpose is to provide
financing for BlueStone. BlueStone owns oil and natural gas
producing properties in Texas. Prior to the Offering, Memorial
Resource owned an 89.45% interest in BlueStone and certain
members of BlueStones management owned a 10.55% interest.
|
|
|
|
Certain carved-out oil and natural gas properties (Classic
Carve-Out) of Classic Hydrocarbons Holdings, L.P,
(Classic) that will be acquired by the Partnership
at the closing of the initial public offering. Classic was
formed in 2006 to engage in the exploration, development,
production, and sale of oil and natural gas primarily in East
Texas. Prior to the Offering, Memorial Resource owned a 90.21%
limited partner interest in Classic and an 83.33% membership
interest in the general partner of Classic.
|
|
|
Note 2
|
Basis of
Presentation and Significant Accounting Policies
|
|
|
(a)
|
Basis
of Presentation
|
The accompanying combined financial statements were derived from
the historical accounting records of the Predecessor and reflect
the historical financial position, results of operations and
cash flows for the periods described herein. All material
intercompany transactions and account balances have been
eliminated in the combination of accounts. The accompanying
combined financial statements have been prepared in accordance
with accounting principles generally accepted in the United
States of America (GAAP). The Predecessor operates
oil and natural gas properties as one business segment: the
exploration, development and production of oil and natural gas.
The Predecessors management evaluates performance based on
one business segment as there are not different economic
environments within the operation of the oil and natural gas
properties.
As common control exists among the Predecessor entities, the
Predecessors combined financial statements reflect the
financial statements of BlueStone and Classic Carve-Out on a
combined basis for the periods presented.
F-23
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
The Classic Carve-Out amounts included in the accompanying
financial statements were determined in accordance with
Regulations S-X, Article 3 General instructions as
to financial statements and Staff Accounting Bulletin
(SAB) Topic 1-B Allocations of Expenses and
Related Disclosure in Financial Statements of Subsidiaries,
Divisions or Lesser Business Components of Another
Entity. Certain expenses incurred by Classic are only
indirectly attributable to its ownership of Classic Carve Out as
Classic owns interests in numerous other oil and natural gas
properties. As a result, certain assumptions and estimates were
made in order to allocate a reasonable share of such expenses to
the Predecessor, so that the amounts included in the
accompanying combined financial statements attributable to
Predecessor reflect substantially all of the cost of doing
business. Such allocations may or may not reflect future costs
associated with the operation of the Partnership.
The preparation of combined financial statements in conformity
with GAAP requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the combined financial statements the reported amounts of
revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Significant estimates include, but are not limited to, oil and
natural gas reserves; depreciation, depletion, and amortization
of proved oil and natural gas properties; future cash flows from
oil and natural gas properties; impairment of long-lived assets;
fair value of derivatives; fair value of equity compensation;
fair values of assets acquired and liabilities assumed in
business combinations and asset retirement obligations.
|
|
(c)
|
Principles
of Consolidation
|
The accompanying combined financial statements include the
accounts of BlueStone and its wholly owned subsidiaries as well
as the accounts of Classic Carve-Out. All material intercompany
balances and transactions have been eliminated.
|
|
(d)
|
Cash
and Cash Equivalents
|
The Predecessor considers all highly liquid instruments with
original contractual maturities of three months or less to be
cash equivalents.
|
|
(e)
|
Concentrations
of Credit Risk
|
Financial instruments which potentially subject the Predecessor
to credit risk consist principally of cash balances, accounts
receivable and derivative financial instruments. The Predecessor
maintains cash and cash equivalents in bank deposit accounts
which, at times, may exceed the federally insured limits.
Management periodically reviews and assesses the financial
condition of the banks to mitigate the risk of loss. Derivative
financial instruments are generally executed with major
financial institutions that expose the Predecessor to market and
credit risks and which may, at times, be concentrated with
certain counterparties. The credit worthiness of the
counterparties is subject to continual review. The Predecessor
also has netting arrangements in place with counterparties to
reduce credit exposure. The Predecessor has not experienced any
losses from such investments.
The Predecessors oil and natural gas sales are to a
variety of purchasers, including intrastate and interstate
pipelines or their marketing affiliates and independent
marketing companies. The Predecessors joint operations
account receivables are from a number of oil and natural gas
companies, partnerships, individuals, and others who own
interests in the properties operated by the Predecessor.
Generally, operators of crude oil and natural gas properties
have the right to offset future revenues against unpaid charges
related to operated wells, minimizing the credit risk associated
with these receivables. Additionally, management believes that
any
F-24
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
credit risk imposed by a concentration in the oil and natural
gas industry is offset by the creditworthiness of the
Predecessors customer base. Management determines amounts
to be uncollectible when the Predecessor has used all reasonable
means of collection and settlement. Amounts outstanding longer
than the contractual terms are considered past due. Management
believes all amounts included in accounts receivable at
March 31, 2011 and December 31, 2010 will be
collected, and therefore, no allowance for uncollectible
accounts has been recorded.
If the Predecessor were to lose any one of its customers, the
loss could temporarily delay production and sale of oil and
natural gas in the related producing region. If the Predecessor
were to lose any single customer, the Predecessor believes that
a substitute customer to purchase the impacted production
volumes could be identified. However, if one or more of the
Predecessors larger customers ceased purchasing oil or
natural gas altogether, the loss of such customer could have a
detrimental effect on production volumes in general and on the
ability to find substitute customers to purchase production
volumes.
|
|
(f)
|
Oil
and Natural Gas Properties
|
The Predecessor accounts for its oil and natural gas
exploration, development and production activities in accordance
with the successful efforts method of accounting. Under this
method, costs of acquiring properties, costs of drilling
successful exploration wells, and development costs are
capitalized. The costs of exploratory wells are initially
capitalized pending a determination of whether proved reserves
have been found. At the completion of drilling activities, the
costs of exploratory wells remain capitalized if determination
is made that proved reserves have been found. If no proved
reserves have been found, the costs of each of the related
exploratory wells are charged to expense. In some cases, a
determination of proved reserves cannot be made at the
completion of drilling, requiring additional testing and
evaluation of the wells. The Predecessors policy is to
expense the costs of such exploratory wells if a determination
of proved reserves has not been made within a twelve-month
period after drilling is complete. Exploration costs such as
geological, geophysical, and seismic costs are expensed as
incurred.
As exploration and development work progresses and the reserves
on these properties are proven, capitalized costs attributed to
the properties are subject to depreciation and depletion.
Depletion of capitalized costs is provided using the
units-of-production
method based on proved oil and gas reserves related to the
associated field. The timing of any write downs of unproven
properties, if warranted, depends upon the nature, timing, and
extent of planned exploration and development activities and
their results.
On the sale or retirement of a complete or partial unit of a
proved property or pipeline and related facilities, the cost and
related accumulated depreciation, depletion, and amortization
are eliminated from the property accounts, and any gain or loss
is recognized.
The estimates of proved oil and natural gas reserves utilized in
the preparation of the combined financial statements are
estimated in accordance with the guidelines established by the
Securities and Exchange Commission (SEC) and the Financial
Accounting Standards Board (FASB), which subsequent to
December 31, 2008 require that reserve estimates be
prepared under existing economic and operating conditions using
a 12-month
average price with no provision for price and cost escalations
in future years except by contractual arrangements. The
Predecessors reserve estimates were prepared by a
third-party petroleum engineer.
Reserve estimates are inherently imprecise. Accordingly, the
estimates are expected to change as more current information
becomes available. The Predecessor depletes its oil and gas
properties by field using the
units-of-production
method. Capitalized drilling and development costs of producing
oil and natural gas properties are depleted over proved
developed reserves and leasehold costs are depleted over total
proved
F-25
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
reserves. It is possible that, because of changes in market
conditions or the inherent imprecision of reserve estimates, the
estimates of future cash inflows, future gross revenues, the
amount of oil and natural gas reserves, the remaining estimated
lives of oil and natural gas properties, or any combination of
the above may be increased or reduced. Increases in recoverable
economic volumes generally reduce per unit depletion rates while
decreases in recoverable economic volumes generally increase per
unit depletion rates.
In January 2010, the FASB issued Accounting Standards Update
2010-03
(ASU
2010-03),
Oil and Gas Reserve Estimations and Disclosures. This
update aligns the current oil and natural gas reserve estimation
and disclosure requirements of ASC Topic 932, Extractive
Activities Oil and Gas, with the requirements in
the Securities and Exchange Commissions final rule,
Modernization of Oil and Gas Reporting Requirements (the
Final Rule), which was issued on December 31,
2008 and was effective for the year ended December 31,
2009. The Final Rule was designed to modernize and update the
oil and natural gas disclosure requirements to align with
current practices and changes in technology.
The Final Rule permits the use of new technologies to determine
proved reserves estimates if those technologies have been
demonstrated empirically to lead to reliable conclusions about
reserve volume estimates. The Final Rule will also allow, but
not require, companies to disclose their probable and possible
reserves to investors. In addition, the new disclosure
requirements require companies to: (i) report the
independence and qualifications of its reserves preparer or
auditor; (ii) file reports when a third party is relied
upon to prepare reserves estimates or conduct a reserves audit;
and (iii) report oil and natural gas reserves using an
average price based upon the prior
12-month
period rather than a year-end price. The Final Rule became
effective for fiscal years ending on or after December 31,
2009. The Predecessors 2009 and 2010 depletion
calculations were based upon proved reserves that were
determined using the new reserve rules; whereas, the depletion
calculation in 2008 was based on the prior SEC methodology.
|
|
(h)
|
Other
Property and Equipment
|
Other property and equipment is stated at historical costs and
is comprised primarily of vehicles, furniture, fixtures, and
computer hardware and software. Depreciation of other property
and equipment is calculated using the straight-line method based
on estimated useful lives of three to five years.
Proved oil and natural gas properties are reviewed for
impairment when events and circumstances indicate a possible
decline in the recoverability of the carrying value of such
properties, such as a downward revision of the reserve
estimates, less than expected production, drilling results, or
lower commodity prices. The estimated future cash flows expected
in connection with the property are compared to the carrying
value of the property to determine if the carrying amount is
recoverable. If the carrying value of the property exceeds its
estimated undiscounted future cash flows, the carrying amount of
the property is reduced to its estimated fair value. The factors
used to determine fair value include, but are not limited to,
estimates of proved reserves, future commodity prices, the
timing of future production and capital expenditures and a
discount rate commensurate with the risk reflective of the lives
remaining for the respective oil and gas properties. The
Predecessor accounts for impairment as a Level 3 fair value
computation.
Nonproducing oil and natural gas properties, which consist of
undeveloped leasehold costs and costs associated with the
purchase of proved undeveloped reserves, are assessed for
impairment on a
property-by-property
basis. If the assessment indicates an impairment, a loss is
recognized by providing a valuation allowance. The impairment
assessment is affected by economic factors such as the results
of exploration activities, commodity price outlooks, remaining
lease terms, and potential shifts in business strategy employed
by management.
F-26
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
|
|
(j)
|
Asset
Retirement Obligations
|
The Predecessor accounts for asset retirement obligations under
ASC Topic 410, Asset Retirement and Environmental
Obligations. ASC 410 requires legal obligations
associated with the retirement of long-lived assets to be
recognized at their fair value at the time that the obligations
are incurred. Oil and gas producing companies incur such a
liability upon acquiring or drilling a well. Under ASC 410,
an asset retirement obligation is recorded as a liability at its
estimated present value at the assets inception, with an
offsetting increase to producing properties in the accompanying
combined balance sheets, which is allocated to expense over the
useful life of the asset. Periodic accretion of the discount on
asset retirement obligations is recorded as an expense in the
accompanying combined statements of operations. Upon settlement
of the liability, a gain or loss is recognized to the extent the
actual costs differ from the recorded liability. The following
table details the change in the asset retirement obligations
between December 31, 2010 and March 31, 2011 (in
thousands):
|
|
|
|
|
Asset retirement obligations at December 31, 2010
|
|
$
|
10,892
|
|
Accretion expense
|
|
|
210
|
|
Revision of estimates
|
|
|
(4)
|
|
|
|
|
|
|
Asset retirement obligations at March 31, 2011
|
|
$
|
11,098
|
|
|
|
|
|
|
|
|
(k)
|
Other
Long-Term Assets
|
Other long-term assets consist of deposits and deferred
financing costs associated with the Predecessors credit
facilities. Deferred financing costs are stated at cost, net of
amortization, and are amortized over the terms of the credit
facilities. Amortization expense for the three months ended
March 31, 2011 and 2010 was approximately $85,000 and
$60,000, respectively.
Oil and natural gas revenues are recorded using the sales
method. Under this method, the Predecessor recognizes revenues
based on actual volumes of oil and natural gas sold to
purchasers. The Predecessor and other joint interest owners may
sell more or less than their entitlement share of volumes
produced. A liability is recorded and revenue is deferred if the
Predecessors excess sales of natural gas volumes exceed
its estimated remaining recoverable reserves. The Predecessor
had no significant natural gas imbalances at March 31, 2011
and December 31, 2010.
|
|
(m)
|
General
and Administrative Expense
|
The Predecessor receives fees for operation of jointly owned oil
and natural gas properties and records such reimbursements as a
reduction of general and administrative expenses. Such fees
totaled approximately $269,000 and $195,000 for the three months
ended March 31, 2011 and 2010, respectively.
|
|
(n)
|
Derivative
Instruments
|
The Predecessor uses derivative financial instruments (swaps,
floors, collars, and forward sales) to reduce the impact of
natural gas and oil price fluctuations and uses interest rate
swaps to manage exposure to interest rate volatility, primarily
as a result of variable rate borrowings under the credit
facilities. Every derivative instrument (including certain
derivative instruments embedded in other contracts) is recorded
in the balance sheet as either an asset or liability measured at
its fair value. Changes in the derivatives fair value are
recognized currently in earnings unless specific hedge
accounting criteria are met. Special accounting for qualifying
hedges allows a derivatives gains and losses to offset
related results on the hedged item in the statements of
operations. Companies must formally document, designate, and
assess the effectiveness of
F-27
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
transactions that receive hedge accounting treatment. The
Predecessor had no derivatives designated as hedges at
March 31, 2011 or December 31, 2010.
Changes in the fair value of derivative financial instruments
that do not qualify for accounting treatment as hedges are
recognized currently in the statements of operations.
The Predecessors entities are not taxpaying entities for
federal income tax purposes, and thus no federal income tax
expense has been recorded in the accompanying combined financial
statements. The partners or members of the Predecessors
entities are responsible for federal income taxes on their
respective share of the Predecessors entities income.
The Predecessors entities are subject to the Texas margin
tax and certain aspects of the tax make it similar to an income
tax as the tax is assessed on 1% of taxable margin. Deferred
taxes related to Texas margin tax arise due to temporary
differences between the financial statement carrying value of
existing assets and liabilities and their respective tax basis.
Deferred tax liabilities at March 31, 2011 and
December 31, 2010 were $225,000. Current tax expense for
the three months ended March 31, 2011 and 2010 was not
material. The Predecessor had no uncertain tax positions that
required recognition in the combined financial statements at
March 31, 2011 and December 31, 2010.
The cost of employee services received in exchange for equity
instruments is measured based on estimated fair value at period
end for liability awards. That cost is recognized as
compensation expense over the requisite service period. Awards
subject to performance criteria vest when it is probable that
the performance criteria will be met and the requisite service
period has been met. Generally, no compensation expense is
recognized for equity instruments that do not vest.
|
|
(q)
|
New
Accounting Pronouncements
|
On July 21, 2010, the FASB issued ASU
2010-20
Receivables (Topic 310) Disclosures about the
Credit Quality of Financial Receivables and the Allowance for
Credit Losses. ASU
2010-20
requires disclosure of additional information to assist
financial statement users to understand more clearly an
entitys credit risk exposures to finance receivables and
the related allowance for credit losses. ASU
2010-20 is
effective for all public companies for interim and annual
reporting periods ending on or after December 15, 2010,
with specific items, such as the allowance rollforward and
modification disclosures, effective for periods beginning after
December 15, 2010. We do not expect the adoption of this
new guidance to have an impact on our financial position, cash
flows or results of operations.
In April 2010, the FASB issued ASU
2010-14,
which amends the guidance on oil and natural gas reporting in
Accounting Standards Codification 932.10.S99-1 by adding the
Codification of SEC
Regulation S-X,
Rule 4-10
as amended by the SEC Final
Rule 33-8995.
Both ASU
2010-03 and
ASU 2010-14
are effective for annual reporting periods ending on or after
December 31, 2009. Application of the revised rules is
prospective and companies are not required to change prior
period presentation to conform to the amendments.
In January 2010, the FASB issued Accounting Standards Update
(ASU)
2010-06,
Fair Value Measurements and Disclosures (Topic 820): Improving
Disclosures about Fair Value Measurements. ASU
2010-06
requires reporting entities to provide information about
movements of assets amount Levels 1 and 2 of the three-tier
fair value hierarchy established by FASB ASC 820. The
guidance is effective for any fiscal year that begins after
December 15, 2009. The Predecessor adopted the provisions
of ASU
2010-06 on
F-28
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
January 1, 2010 and this ASU did not have a material impact
on the Predecessors financial position, results of
operations or cash flows.
|
|
Note 3
|
Acquisitions
and Divestitures
|
Effective January 1, 2010, the Predecessor acquired
producing oil and natural gas properties in East Texas from
Petrohawk Properties, LP for approximately $5.8 million.
The net purchase price of $5.8 million was allocated to
proved oil and gas properties. The acquisition closed on
May 28, 2010.
Effective March 1, 2010, the Predecessor acquired oil and
natural gas properties in East Texas from BP America Production
Company for approximately $8.2 million. The net purchase
price was allocated to proved oil and gas properties. This
acquisition closed on March 29, 2010.
Effective April 1, 2010, the Predecessor acquired Forest
Oils interests in wells located in Webb County, Texas for
a net purchase price of approximately $65.9 million. The
net purchase price was allocated to oil and gas properties. This
acquisition of properties closed on June 30, 2010.
Effective May 1, 2010, the Predecessor acquired Merit
Energys interest in wells located in South Texas for a net
purchase price of approximately $14.1 million. The net
purchase price was allocated as follows (in thousands):
|
|
|
|
|
Oil and gas properties
|
|
$
|
15,397
|
|
Prepaid assets
|
|
|
450
|
|
Assumed liabilities
|
|
|
(1,728)
|
|
|
|
|
|
|
Net purchase price
|
|
$
|
14,119
|
|
|
|
|
|
|
As part of the acquisition process, an environmental review was
performed and it was determined that there was environmental
damage to one of the acquired properties. As such, the parties
agreed to reduce the purchase price by $550,000. Additionally,
the Predecessor and Merit entered into an escrow agreement where
the Predecessor agreed to pay for the initial $1.0 million
of the remediation costs, with Merit paying for gross amounts
incurred in excess of $1.0 million and up to
$1.45 million. The Predecessors anticipated cost to
remediate this area is $1.45 million. As of March 31,
2011 and December 31, 2010, the Predecessor has recorded an
accrued liability of $1.45 million for these remediation
costs. Merit has funded an escrow account with the $450,000 and
that amount is included in the accompanying balance sheet as a
prepaid asset. This acquisition closed on June 4, 2010.
Effective May 1, 2010, the Predecessor acquired Zachry
Exploration, LLCs interest in the Predecessors
Laredo area properties for a net purchase price of
$6.5 million. The net purchase price was allocated to oil
and gas properties. This acquisition closed on August 3,
2010.
Effective April 1, 2010, the Predecessor acquired
U.S. Enercorp, LTDs interest in wells located in
McMullen County, Texas for a net purchase price of approximately
$2.6 million. The net purchase price was allocated to oil
and gas properties. This acquisition closed on May 28, 2010.
The Predecessor also acquired interests in oil and gas
properties, including acreage, in a number of individually
insignificant acquisitions during the three months ended
March 31, 2011 which aggregated to a total of approximately
$1.7 million. There were no individually insignificant
acquisitions during the three months ended March 31, 2010.
Included in other expense in the accompanying combined
statements of operations for the three months ended
March 31, 2011 are approximately $39,000 of acquisition
costs related to acquisitions. There were no acquisition costs
for the March 31, 2010 period.
On January 20, 2010, the Predecessor sold its interests in
the Saner wells for net proceeds of approximately
$1.4 million. There was no significant gain or loss
associated with this sale.
Results of operations for all acquisitions are included in the
Predecessors combined financial statements from the
respective closing date forward.
F-29
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
|
|
Note 4
|
Fair
Value Measurements of Financial Instruments
|
The Predecessor uses a valuation framework based upon inputs
that market participants use in pricing an asset or liability,
which are classified into two categories: observable inputs and
unobservable inputs. Observable inputs represent market data
obtained from independent sources; whereas, unobservable inputs
reflect a companys own market assumptions, which are used
if observable inputs are not reasonably available without undue
cost and effort. These two types of inputs are further divided
into the following fair value input hierarchy:
Level 1 Unadjusted quoted prices
in active markets that are accessible at the measurement date
for identical, unrestricted assets or liabilities. The
Predecessor considers active markets to be those in which
transactions for the assets or liabilities occur in sufficient
frequency and volume to provide pricing information on an
ongoing basis.
Level 2 Quoted prices in markets
that are not active, or inputs that are observable, either
directly or indirectly, for substantially the full term of the
asset or liability. This category includes those derivative
instruments that the Predecessor values using observable market
data. Substantially all of these inputs are observable in the
marketplace throughout the full term of the derivative
instrument, can be derived from observable data, or are
supported by observable levels at which transactions are
executed in the marketplace. Level 2 instruments primarily
include non-exchange-traded derivatives, such as
over-the-counter
commodity price swaps, collars, put options and interest rate
swaps. At March 31, 2011 and December 31, 2010, all of
the Predecessors derivative instruments were considered
Level 2.
Level 3 Measure based on prices
or valuation models that require inputs that are both
significant to the fair value measurement and are less
observable from objective sources (i.e., supported by little or
no market activity).
Assets
and Liabilities Measured at Fair Value on a Recurring
Basis
The carrying values of cash and cash equivalents, accounts
receivables, accounts payables (including accrued liabilities)
and amounts outstanding under long-term debt agreements included
in the accompanying combined balance sheets approximated fair
value at March 31, 2011 and December 31, 2010. These
assets and liabilities are not presented in the following tables.
Derivative Instruments The fair market
values of the derivative financial instruments reflected in the
combined balance sheets were based on quotes obtained from the
counterparties to the agreements. Financial assets and
liabilities are classified based on the lowest level of input
that is significant to the fair value measurement. The
Predecessors assessment of the significance of a
particular input to the fair value measurement requires
judgment, and may affect the valuation of the fair value of
assets and liabilities and their placement within the fair value
hierarchy levels.
The fair value input hierarchy to which an asset or liability
measurement falls is determined based on the lowest-level input
that is significant to the measurement in its entirety. The
following table presents the Predecessors assets and
liabilities that are measured at fair value on a recurring basis
at March 31, 2011 and December 31, 2010 for each of
the fair value hierarchy levels (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at March 31, 2011 Using
|
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
Quoted Prices in
|
|
|
Significant Other
|
|
|
Unobservable
|
|
|
|
|
|
|
Active Markets
|
|
|
Observable Inputs
|
|
|
Inputs
|
|
|
Fair Value at
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
March 31, 2011
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
$
|
|
|
|
$
|
2,589
|
|
|
$
|
|
|
|
$
|
2,589
|
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
3,589
|
|
|
|
|
|
|
|
3,589
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
|
|
|
$
|
6,178
|
|
|
$
|
|
|
|
$
|
6,178
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-30
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at March 31, 2011 Using
|
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
Quoted Prices in
|
|
|
Significant Other
|
|
|
Unobservable
|
|
|
|
|
|
|
Active Markets
|
|
|
Observable Inputs
|
|
|
Inputs
|
|
|
Fair Value at
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
March 31, 2011
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
$
|
|
|
|
$
|
(43)
|
|
|
$
|
|
|
|
$
|
(43)
|
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
(1,155)
|
|
|
|
|
|
|
|
(1,155)
|
|
Commodity derivative put option
|
|
|
|
|
|
|
(270)
|
|
|
|
|
|
|
|
(270)
|
|
Commodity derivative interest rate swaps
|
|
|
|
|
|
|
(335)
|
|
|
|
|
|
|
|
(335)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
|
|
|
$
|
(1,803)
|
|
|
$
|
|
|
|
$
|
(1,803)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2010 Using
|
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
Quoted Prices in
|
|
|
Significant Other
|
|
|
Unobservable
|
|
|
Fair Value at
|
|
|
|
Active Markets
|
|
|
Observable Inputs
|
|
|
Inputs
|
|
|
December 31,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
2010
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
$
|
|
|
|
$
|
3,067
|
|
|
$
|
|
|
|
$
|
3,067
|
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
4,086
|
|
|
|
|
|
|
|
4,086
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
|
|
|
$
|
7,153
|
|
|
$
|
|
|
|
$
|
7,153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price collar contracts
|
|
$
|
|
|
|
$
|
(420)
|
|
|
$
|
|
|
|
$
|
(420)
|
|
Commodity derivative put options
|
|
|
|
|
|
|
(58)
|
|
|
|
|
|
|
|
(58)
|
|
Commodity derivative interest rate swaps
|
|
|
|
|
|
|
(403)
|
|
|
|
|
|
|
|
(403)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
|
|
|
$
|
(881)
|
|
|
$
|
|
|
|
$
|
(881)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For additional information on the Predecessors derivative
instruments, see Note 5.
Assets
and Liabilities Measured at Fair Value on a Nonrecurring
Basis:
Certain assets and liabilities are reported at fair value on a
nonrecurring basis in the Predecessors combined balance
sheets. The following methods and assumptions were used to
estimate the fair values:
Asset Retirement Obligations
(AROs) The Predecessor estimates the
fair value of AROs based on discounted cash flow
projections using numerous estimates, assumptions, and judgments
regarding such factors as the existence of a legal obligation
for an ARO; amounts and timing of settlements; the
credit-adjusted risk-free rate to be used; and inflation rates.
See Note 2 for a summary of changes in AROs.
Properties Acquired in Business
Combinations If sufficient market data is
not available, the Predecessor determines the fair values of
proved and unproved properties acquired in transactions
accounted for as business combinations by preparing estimates of
discounted cash flow projections. The factors to determine fair
value include, but are not limited to, estimates of proved
reserves, future
F-31
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
commodity prices, the timing of future production and capital
expenditures and a discount rate commensurate with the risk
reflective of the lives remaining for the respective oil and gas
properties.
|
|
Note 5
|
Risk
Management and Derivative Instruments
|
The Predecessor utilizes derivative instruments to manage
exposure to commodity price and interest rate fluctuations and
achieve a more predictable cash flow in connection with its
natural gas and oil sales from production and borrowing related
activities. These transactions limit exposure to declines in
prices or increases in interest rates, but also limit the
benefits the Predecessor would realize if prices increase or
interest rates decrease.
Inherent in the Predecessors portfolio of natural gas and
interest rate derivative contracts are certain business risks,
including market risk and credit risk. Market risk is the risk
that the price of natural gas will change, either favorably or
unfavorably, in response to changing market conditions. Credit
risk is the risk of loss from nonperformance by the
Predecessors counterparty to a contract. The Predecessor
does not require collateral from its counterparties but does
attempt to minimize its credit risk associated with derivative
instruments by limiting its exposure to any single counterparty
and entering into derivative instruments only with
counterparties that are large financial institutions, which
management believes present minimal credit risk. In addition, to
mitigate its risk of loss due to default, the Predecessor has
entered into master netting agreements with its counterparties
on its derivative instruments that allow the Predecessor to
offset its asset position with its liability position in the
event of default by the counterparty. Had the Predecessors
counterparties failed to perform under existing derivative
contracts, the maximum loss at March 31, 2011 would be
approximately $4,375,000.
|
|
(a)
|
Commodity
Derivatives
|
The Predecessor uses a combination of natural gas swaps,
costless collars and put options to manage its exposure to
commodity price volatility. At March 31, 2011, the
Predecessor had the following open commodity positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps
|
|
|
|
|
Average Monthly
|
|
Weighted Average
|
Beginning Month
|
|
Ending Month
|
|
Volumes (MMBtu)
|
|
Fixed Price
|
|
|
1/1/2011
|
|
|
|
12/31/2011
|
|
|
|
88,000
|
|
|
$
|
6.11
|
|
|
2/1/2011
|
|
|
|
6/30/2011
|
|
|
|
54,000
|
|
|
$
|
4.10
|
|
|
1/1/2012
|
|
|
|
6/30/2012
|
|
|
|
15,000
|
|
|
$
|
5.35
|
|
|
1/1/2012
|
|
|
|
12/31/2012
|
|
|
|
90,000
|
|
|
$
|
5.81
|
|
|
1/1/2013
|
|
|
|
12/31/2013
|
|
|
|
61,000
|
|
|
$
|
5.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Collars
|
|
|
|
|
Average Monthly
|
|
Weighted Average
|
|
Weighted Average
|
Beginning Month
|
|
Ending Month
|
|
Volumes (MMBtu)
|
|
Floor Price
|
|
Ceiling Price
|
|
1/1/2011
|
|
4/30/2011
|
|
6,000
|
|
$
|
6.25
|
|
|
$
|
7.25
|
|
1/1/2011
|
|
8/31/2011
|
|
6,000
|
|
$
|
6.25
|
|
|
$
|
7.15
|
|
1/1/2011
|
|
12/31/2011
|
|
193,000
|
|
$
|
5.28
|
|
|
$
|
6.75
|
|
7/1/2011
|
|
12/31/2011
|
|
21,000
|
|
$
|
4.00
|
|
|
$
|
5.00
|
|
1/1/2012
|
|
12/31/2012
|
|
275,000
|
|
$
|
4.88
|
|
|
$
|
6.19
|
|
1/1/2013
|
|
12/31/2013
|
|
349,000
|
|
$
|
4.76
|
|
|
$
|
5.79
|
|
F-32
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Put Options
|
|
|
|
|
|
|
|
Average Monthly
|
|
|
|
|
Beginning Month
|
|
|
Ending Month
|
|
|
Volumes (MMBtu)
|
|
|
Strike Price
|
|
|
|
1/1/2011
|
|
|
|
12/31/2011
|
|
|
|
250,000
|
|
|
$
|
4.30
|
|
|
1/1/2012
|
|
|
|
12/31/2012
|
|
|
|
70,000
|
|
|
$
|
4.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Collars
|
|
|
|
|
Average Monthly
|
|
Weighted Average
|
|
Weighted Average
|
Beginning Month
|
|
Ending Month
|
|
Volumes (Bbls)
|
|
Floor Price
|
|
Ceiling Price
|
|
|
1/1/2011
|
|
|
12/31/2011
|
|
1,200
|
|
$
|
75.00
|
|
|
$
|
94.00
|
|
|
1/1/2012
|
|
|
12/31/2012
|
|
900
|
|
$
|
73.33
|
|
|
$
|
94.97
|
|
|
1/1/2013
|
|
|
6/30/2013
|
|
300
|
|
$
|
80.00
|
|
|
$
|
99.60
|
|
|
1/1/2013
|
|
|
12/31/2013
|
|
600
|
|
$
|
70.00
|
|
|
$
|
104.70
|
|
In June 2010, the Predecessor entered into an interest rate swap
agreement in order to mitigate its exposure to interest rate
fluctuations. Under this swap agreement, the Predecessor
receives the current
1-month
LIBOR and pays a fixed rate of 1.00% on a notional amount of
$50.0 million. The effective date of the swap is from June
2010 to June 2012.
In 2009, the Predecessor entered into two interest rate swap
agreements in order to mitigate its exposure to interest rate
fluctuations. Under these swap agreements, the Predecessor pays
1.62% and receives the current
3-month
LIBOR rate per month on a notional amount of $6.7 million
and $1.7 million, respectively. The effective dates of the
swaps were from February 2009 to February 2011.
The interest rate swaps are not designated as hedges for
financial accounting purposes. All gains and losses, including
unrealized gains and losses related to the change in the
interest rate swaps fair value, have been recorded in interest
expense in the combined statements of operations.
|
|
(c)
|
Balance
Sheet Presentation
|
The following table summarizes the gross fair value of
derivative instruments by the appropriate balance sheet
classification, even when the derivative instruments are subject
to netting arrangements and qualify for net presentation in the
Predecessors combined balance sheets at March 31,
2011 and December 31, 2010 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
Type
|
|
Balance Sheet Location(1)
|
|
2011
|
|
|
2010
|
|
|
Natural Gas Swaps
|
|
Short-term derivative instruments Current assets
|
|
$
|
1,309
|
|
|
$
|
1,661
|
|
Natural Gas Collars
|
|
Short-term derivative instruments Current assets
|
|
|
2,124
|
|
|
|
2,459
|
|
Natural Gas Swaps
|
|
Long-term derivative instruments Long-term assets
|
|
|
1,279
|
|
|
|
1,406
|
|
Natural Gas Collars
|
|
Long-term derivative instruments Long-term assets
|
|
|
1,465
|
|
|
|
1,627
|
|
Natural Gas Puts
|
|
Short-term derivative instruments Current liabilities
|
|
|
(224)
|
|
|
|
(23)
|
|
Natural Gas Collars
|
|
Short-term derivative instruments Current liabilities
|
|
|
(167)
|
|
|
|
(56)
|
|
Natural Gas Swaps
|
|
Short-term derivative instruments Current liabilities
|
|
|
(43)
|
|
|
|
|
|
Oil Collars
|
|
Short-term derivative instruments Current liabilities
|
|
|
(186)
|
|
|
|
(81)
|
|
Interest Rate Swaps
|
|
Short-term derivative instruments Current liabilities
|
|
|
(268)
|
|
|
|
(153)
|
|
Natural Gas Puts
|
|
Long-term derivative instruments Long-term
liabilities
|
|
|
(45)
|
|
|
|
(35)
|
|
Natural Gas Swaps
|
|
Long-term derivative instruments Long-term
liabilities
|
|
|
|
|
|
|
|
|
F-33
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
|
December 31,
|
|
Type
|
|
Balance Sheet Location(1)
|
|
2011
|
|
|
2010
|
|
|
Natural Gas Collars
|
|
Long-term derivative instruments Long-term
liabilities
|
|
|
(527)
|
|
|
|
(174)
|
|
Oil Collars
|
|
Long-term derivative instruments Long-term
liabilities
|
|
|
(275)
|
|
|
|
(109)
|
|
Interest Rate Swaps
|
|
Long-term derivative instruments Long-term
liabilities
|
|
|
(67)
|
|
|
|
(250)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative financial instruments
|
|
$
|
4,375
|
|
|
$
|
6,272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The fair value of derivative instruments reported in the
Predecessors combined balance sheets are subject to
netting arrangements and qualify for net presentation. The
following table reports the net derivative fair values as
reported in the Predecessors combined balance sheets at
March 31, 2011 and December 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
March 31, 2011
|
|
|
December 31, 2010
|
|
|
Combined balance sheet classification:
|
|
|
|
|
|
|
|
|
Current derivative contracts:
|
|
|
|
|
|
|
|
|
Assets
|
|
$
|
2,694
|
|
|
$
|
3,791
|
|
Liabilities
|
|
|
(186)
|
|
|
|
(109)
|
|
|
|
|
|
|
|
|
|
|
Net current
|
|
$
|
2,508
|
|
|
$
|
3,682
|
|
|
|
|
|
|
|
|
|
|
Noncurrent derivative contracts:
|
|
|
|
|
|
|
|
|
Assets
|
|
$
|
2,142
|
|
|
$
|
2,699
|
|
Liabilities
|
|
|
(275)
|
|
|
|
(109)
|
|
|
|
|
|
|
|
|
|
|
Net noncurrent
|
|
$
|
1,867
|
|
|
$
|
2,590
|
|
|
|
|
|
|
|
|
|
|
|
|
(d)
|
Gains
(Losses) on Derivatives
|
The Predecessor does not designate its derivative instruments as
hedging instruments for financial reporting purposes.
Accordingly, all gains and losses, including unrealized gains
and losses from changes in the derivative instruments fair
values, have been recorded in the combined statements of
operations. The following table details the unrealized and
realized gains and losses related to derivative instruments for
the three months ending March 31, 2011 and 2010 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Statements of
|
|
|
|
|
|
|
|
|
Operations
|
|
Three Months Ended
|
|
|
|
Location
|
|
March 31, 2011
|
|
|
March 31, 2010
|
|
|
|
|
Gain/(loss)on
|
|
|
|
|
|
|
|
|
Commodity derivative contracts(1)
|
|
derivatives
|
|
|
(703)
|
|
|
|
6,636
|
|
Interest rate swaps(2)
|
|
Interest expense
|
|
|
53
|
|
|
|
28
|
|
|
|
|
(1) |
|
Included in these amounts are net cash receipts of approximately
$1,259 and $930 for the three months ended March 31, 2011
and March 31, 2010, respectively. |
|
(2) |
|
Included in the amounts are net cash payments of approximately
$118 and $26 for the three months ended March 31, 2011 and
March 31, 2010, respectively. |
The
BlueStone Credit Facility
On July 8, 2009, BlueStone refinanced its existing
$100.0 million credit agreement with Bank of America, N.A.
by entering into a $150.0 million revolving credit facility
with various lenders. The $150.0 million credit
F-34
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
facility had an original maturity date of July 8, 2012, at
which time all principal and accrued interest amounts were due.
On June 25, 2010, BlueStone refinanced this credit facility
and entered into a $150.0 million revolving credit facility
with Wells Fargo Bank, NA (Wells Fargo) as
Administrative Agent. Amounts outstanding under the Wells Fargo
credit facility are payable on June 25, 2014 with mandatory
payments required if BlueStone makes any property dispositions.
At March 31, 2011 and December 31, 2010,
$80.3 million and $80.2 million, respectively, were
outstanding under the Wells Fargo credit facility.
Amounts outstanding under the Wells Fargo credit facility are
limited to a borrowing base which is determined twice per year.
In addition, BlueStone and the Administrative Agent can request
special borrowing base determinations, from time to time. If the
outstanding principal balance of the revolving credit facility
exceeds the borrowing base at any time, BlueStone must either
(a) reduce amounts outstanding under the revolving credit
facility in an amount to cure the deficiency, (b) pledge
additional oil and gas property as collateral sufficient to cure
the deficiency or (c) make monthly principal payments in
amounts that will cure the deficiency over the ensuing six-month
period. The borrowing base was $90.0 million at
March 31, 2011 and the borrowing base availability was
$9.4 million at March 31, 2011.
Adjusted Base Rate Advances and Adjusted LIBOR Rate Advances
under the revolving credit facility bear interest, payable
monthly, at an Adjusted Base Rate or Adjusted LIBOR Rate plus an
applicable margin of 1.75% and 2.75%, respectively. The weighted
average interest rate related to amounts outstanding under the
credit facility were approximately 3.04% and 3.24% for the three
months ended March 31, 2011 and 2010, respectively. The
Wells Fargo revolving credit facility also requires an annual
commitment fee of 0.5%, payable quarterly.
Additionally, the revolving credit facility provides for the
issuance of letters of credit, limited to the total availability
under the facility. At March 31, 2011 and December 31,
2010, BlueStone had $400,000 in letters of credit outstanding
under the facility.
BlueStones borrowings are secured by its assets and stock
and are subject to various financial and nonfinancial covenants.
Significant financial covenants include maintaining: (1) a
minimum current ratio, as defined, of 1.0 to 1.0, (2) a
minimum of EBITDA to interest expense, as defined, of 3.0 to
1.0, for the previous four quarters, and (3) a maximum of
total debt to EBITDA for the previous four quarters, as defined,
of 4.0 to 1.0. At March 31, 2011 and December 31,
2010, BlueStone was in compliance with its debt covenants.
The
Classic Credit Facility
The Classic Carve-Out properties are burdened by debt incurred
pursuant to a $150.0 million revolving credit facility
extended to Classic. Of the $102.0 million outstanding
under this facility at March 31, 2011, $32.2 million
pertained to the Classic Carve-Out properties. The Classic
credit facility has a termination date of June 21, 2014.
Borrowings under the Classic credit facility bear interest, at
the option of Classic, at either the Prime Rate plus an
applicable margin of 1.00% to 2.00% or LIBOR plus and applicable
margin of 2.00% or 3.00%. The margin rate is determined by the
percentage of the borrowing base outstanding. The weighted
average interest rate for the three months ended March 31,
2011 and 2010 was 3.46% and 3.09%, respectively.
The borrowings under the Classic credit facility are secured by
the oil and gas properties of Classic and are subject to
semiannual borrowing base redeterminations. The borrowing base
at March 31, 2011 was $115.0 million, including
$36.3 million allocable to the Classic Carve-Out
properties. At March 31, 2011 and December 31, 2010,
Classic was in compliance under existing debt covenants.
|
|
Note 7
|
Partners
Capital
|
The Predecessor generally allocates income and losses to the
partners based on each partners ownership percentage.
F-35
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
On February 6, 2006, BlueStone, Holdings and Holdings
members entered into a subscription and contribution agreement
whereby all equity contributions made by Holdings members
in exchange for equity units would be transferred directly to
BlueStone.
According to the Subscription and Contributions Agreement and
Amendments, members of Holdings have committed
$84.7 million in equity contributions as of
December 31, 2010. NGP VIII committed $75.7 million.
The remaining $9.0 million was committed by certain members
of BlueStones management. In 2010, BlueStone received an
equity contribution from members of Holdings of an additional
$40 million, including equity contributions of
$4.2 million from management. NGP VIII advanced certain
members of management $4.2 million to fund their equity
contributions in 2010. In exchange for these advances,
management issued notes payable which carry an interest rate of
2.72% and are payable May 28, 2015. The notes can be
declared immediately due and payable if the holder is no longer
employed by BlueStone or upon a merger, sale, or sale of
substantially all assets of BlueStone. At March 31, 2011
and December 31, 2010, 100% of committed equity had been
contributed. There were no capital contributions during the
three months ending March 31, 2011.
On June 6, 2006, the partners of Classic entered into a
Limited Partnership Agreement (the Partnership
Agreement). According to the Partnership Agreement and
Amendments, partners of Classic have committed
$135.9 million in capital contributions as of
December 31, 2010, including $35.7 million allocable
to Classic Carve-Out. NGP VIII committed $123.0 million and
the remaining $12.9 million was committed by certain
members of Classics management. In 2010, Classic received
capital contributions of $19.7 million, net of equity
financing fees, from its partners, including $4.1 million
allocable to Classic Carve-Out. During the three months ended
March 31, 2011, Classic received capital contributions of
$21.9 million, net of equity financing fees, for its
partners, including $4.2 million allocable to Classic
Carve-Out. As of March 31, 2011, 100% of committed capital
had been contributed.
|
|
Note 8
|
Incentive
Interests
|
At March 31, 2011, BlueStone and Classic each had incentive
units outstanding under their respective operating agreements.
The BlueStone and Classic operating agreements provide for the
issuance of up to 2,102,547 and 30,000 units, respectively.
Holders of incentive units are entitled to cash distributions
following the sale, merger, or other transaction involving the
stock or assets of the companies after the recovery of capital
contributions plus a rate of return, specified as payout levels
in their respective operating agreements.
Incentive units are subject to vesting or performance criteria,
as specified in the operating agreements. All incentive units
not vested are forfeited if an employee is no longer employed
and are forfeited automatically after February 6, 2014 for
BlueStone and October 26, 2012 for Classic.
The incentive units are accounted for as liability awards with
compensation expense based on period-end fair value. Because it
is not probable that the performance criterion has been met at
March 31, 2011, no compensation expense has been recorded
for any period in the combined Predecessor financial statements.
|
|
Note 9
|
Related
Party Transactions
|
The majority partner of the Predecessor, NGP VIII, is an
affiliate of certain directors of the entities comprising the
Predecessor.
During the three months ended March 31, 2011 and 2010, the
Predecessor expensed advisory and directors fees of
approximately $36,000 to NGP VIII. At March 31, 2011 and
December 31, 2010 approximately $32,000 related to these
fees was recorded as a related-party payable.
F-36
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
|
|
Note 10
|
Commitments
and Contingencies
|
The Predecessor leases equipment and office space under
operating leases expiring on various dates through 2015. Rent
expense was approximately $71,000 and $50,000 for the three
months ended March 31, 2011 and 2010, respectively.
The Predecessor is involved in litigation in the normal course
of business. Management does not believe the outcome of these
matters will have a material adverse impact on the
Predecessors financial condition or results of operations.
|
|
(c)
|
Noncompete
Agreements
|
The Predecessor entered into noncompete agreements with certain
key employees which, in the event of the employees
termination for other than cause (as defined in the noncompete
agreements), provide for payments equal to the employees
regular monthly salary for a time period to be determined by the
Predecessor, but not to exceed 18 months.
|
|
Note 11
|
Defined
Contribution Plan
|
The companies comprising the Predecessor sponsor defined
contribution plans for the benefit of substantially all
employees who have attained 18 years of age. The plan
allows eligible employees to make tax-deferred contributions up
to 100% of their annual compensation, not to exceed annual
limits established by the Internal Revenue Service. The
Predecessor makes matching contributions of up to 6% of an
employees compensation and may make additional
discretionary contributions for eligible employees meeting
certain plan requirements. Employees vest ratably in the
employer discretionary contributions over three years. The
Predecessors contributions to the plan were approximately
$45,000 and $35,000 in the three months ended March 31,
2011 and 2010, respectively.
|
|
Note 12
|
Subsequent
Events
|
Effective January 1, 2011, the Predecessor acquired BP
America Production Companys (BP) interests in
wells located in Duval, Jim Hogg, McMullen and Webb counties in
exchange for the Predecessors interest in the Nueces Field
of the Eagle Ford Shale and $20 million in cash, subject to
certain closing adjustments. The transaction closed on
May 31, 2011 and the Predecessor paid a total of
approximately $12.9 million in cash consideration at
closing, net of adjustments.
The Predecessor estimated that as of May 31, 2011, the
preliminary fair value of the net assets acquired from BP was
approximately $78.6 million. Taking into consideration the
cash consideration paid at closing of $12.9 million and the
carrying value of approximately $1.6 million for the assets
sold to BP in the transaction, which was primarily acreage, the
Predecessor expects to record a gain of approximately
$64 million during the
2nd
quarter of 2011. The purchase price allocation remains
preliminary and is subject to change until the purchase price
allocation is finalized.
On April 8, 2011, WHT acquired certain oil and natural gas
properties and related assets in East Texas from third party for
approximately $315 million ($302.8 million after
customary adjustments) of which 40% will be contributed to the
Partnership.
F-37
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors
Memorial Production Partners GP LLC:
We have audited the accompanying combined balance sheets of
Memorial Production Partners LP Predecessor (as described in
Note 1 to the financial statements) as of December 31,
2010 and 2009, and the related combined statements of
operations, partners capital, and cash flows for each of
the years in the three-year period ended December 31, 2010.
These combined financial statements are the responsibility of
the Memorial Production Partners LPs management. Our
responsibility is to express an opinion on these combined
financial statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the combined financial statements referred to
above present fairly, in all material respects, the financial
position of Memorial Production Partners LP Predecessor as of
December 31, 2010 and 2009, and the results of its
operations and its cash flows for each of the years in the
three-year period ended December 31, 2010, in conformity
with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Dallas, TX
June 22, 2011
F-38
PREDECESSOR
DECEMBER
31, 2010 AND 2009
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
5,654
|
|
|
$
|
5,297
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
|
6,175
|
|
|
|
5,025
|
|
Joint interest owners and other
|
|
|
3,848
|
|
|
|
2,362
|
|
Short-term derivative instruments
|
|
|
3,791
|
|
|
|
3,086
|
|
Prepaid expenses and other current assets
|
|
|
771
|
|
|
|
1,110
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
20,239
|
|
|
|
16,880
|
|
Property and equipment, at cost:
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, successful efforts method
|
|
|
314,975
|
|
|
|
187,217
|
|
Other
|
|
|
2,553
|
|
|
|
2,137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
317,528
|
|
|
|
189,354
|
|
Accumulated depreciation, depletion and impairment
|
|
|
(93,224)
|
|
|
|
(61,358)
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, net
|
|
|
224,304
|
|
|
|
127,996
|
|
Long-term derivative instruments
|
|
|
2,699
|
|
|
|
814
|
|
Other long-term assets
|
|
|
1,298
|
|
|
|
463
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
248,540
|
|
|
$
|
146,153
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
8,482
|
|
|
$
|
3,442
|
|
Revenues payable
|
|
|
3,564
|
|
|
|
3,140
|
|
Accrued liabilities
|
|
|
3,874
|
|
|
|
654
|
|
Current portion of long-term debt
|
|
|
69
|
|
|
|
24
|
|
Short-term derivative instruments
|
|
|
109
|
|
|
|
13
|
|
Asset retirement obligations
|
|
|
25
|
|
|
|
113
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
16,123
|
|
|
|
7,386
|
|
Long-term debt
|
|
|
115,359
|
|
|
|
61,760
|
|
Deferred tax liabilities
|
|
|
225
|
|
|
|
|
|
Asset retirement obligations
|
|
|
10,867
|
|
|
|
3,693
|
|
Long-term derivative instruments
|
|
|
109
|
|
|
|
288
|
|
Other long-term liabilities
|
|
|
56
|
|
|
|
38
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
142,739
|
|
|
|
73,165
|
|
Commitments and contingencies (Note 11)
|
|
|
|
|
|
|
|
|
Partners capital
|
|
|
105,801
|
|
|
|
72,988
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
248,540
|
|
|
$
|
146,153
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to combined financial statements.
F-39
PREDECESSOR
DECEMBER
31, 2010, 2009 AND 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & natural gas sales
|
|
$
|
37,308
|
|
|
$
|
24,541
|
|
|
$
|
49,313
|
|
Other income
|
|
|
1,433
|
|
|
|
319
|
|
|
|
622
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
38,741
|
|
|
|
24,860
|
|
|
|
49,935
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
13,974
|
|
|
|
11,207
|
|
|
|
8,843
|
|
Exploration
|
|
|
39
|
|
|
|
2,690
|
|
|
|
374
|
|
Production and advalorem taxes
|
|
|
2,112
|
|
|
|
1,464
|
|
|
|
3,127
|
|
Depreciation, depletion and amortization
|
|
|
20,066
|
|
|
|
15,226
|
|
|
|
12,353
|
|
Impairment of proved oil and natural gas properties
|
|
|
11,800
|
|
|
|
3,480
|
|
|
|
14,166
|
|
General and administrative
|
|
|
6,116
|
|
|
|
4,811
|
|
|
|
3,835
|
|
Accretion
|
|
|
663
|
|
|
|
320
|
|
|
|
224
|
|
Gain on derivative instruments
|
|
|
(10,264)
|
|
|
|
(10,834)
|
|
|
|
(9,815)
|
|
Gain on sale of properties
|
|
|
(1)
|
|
|
|
(7,851)
|
|
|
|
(7,395)
|
|
Other, net
|
|
|
890
|
|
|
|
304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
45,395
|
|
|
|
20,817
|
|
|
|
25,712
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating (loss) income
|
|
|
(6,654)
|
|
|
|
4,043
|
|
|
|
24,223
|
|
Interest expense
|
|
|
(4,438)
|
|
|
|
(2,937)
|
|
|
|
(3,138)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
(11,092)
|
|
|
|
1,106
|
|
|
|
21,085
|
|
Income tax expense
|
|
|
(225)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(11,317)
|
|
|
$
|
1,106
|
|
|
$
|
21,085
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to combined financial statements.
F-40
PREDECESSOR
DECEMBER
31, 2010, 2009 AND 2008
|
|
|
|
|
|
|
Total Partners
|
|
|
|
Capital
|
|
|
|
(In thousands)
|
|
|
Balance January 1, 2008
|
|
$
|
37,682
|
|
Contributions from partners
|
|
|
|
|
Distributions to partners
|
|
|
(4,191)
|
|
Net income
|
|
|
21,085
|
|
|
|
|
|
|
Balance December 31, 2008
|
|
|
54,576
|
|
Contributions from partners
|
|
|
17,306
|
|
Distributions to partners
|
|
|
|
|
Net income
|
|
|
1,106
|
|
|
|
|
|
|
Balance December 31, 2009
|
|
|
72,988
|
|
Contributions from partners
|
|
|
44,130
|
|
Distributions to partners
|
|
|
|
|
Net loss
|
|
|
(11,317)
|
|
|
|
|
|
|
Balance December 31, 2010
|
|
$
|
105,801
|
|
|
|
|
|
|
See accompanying notes to combined financial statements.
F-41
PREDECESSOR
DECEMBER
31, 2010, 2009 AND 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(11,317
|
)
|
|
$
|
1,106
|
|
|
$
|
21,085
|
|
Adjustments to reconcile net (loss) income to net cash provided
|
|
|
|
|
|
|
|
|
|
|
|
|
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, and amortization
|
|
|
20,066
|
|
|
|
15,226
|
|
|
|
12,353
|
|
Impairment of proved oil and natural gas properties
|
|
|
11,800
|
|
|
|
3,480
|
|
|
|
14,166
|
|
Unrealized (gain) loss on derivatives
|
|
|
(2,674
|
)
|
|
|
6,430
|
|
|
|
(9,975
|
)
|
Deferred income tax expense
|
|
|
225
|
|
|
|
|
|
|
|
|
|
Amortization of loan origination fees
|
|
|
745
|
|
|
|
109
|
|
|
|
26
|
|
Accretion
|
|
|
663
|
|
|
|
320
|
|
|
|
224
|
|
Gain on sale of properties
|
|
|
(1
|
)
|
|
|
(7,851
|
)
|
|
|
(7,395
|
)
|
Exploratory dry hole costs
|
|
|
39
|
|
|
|
2,690
|
|
|
|
374
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(2,637
|
)
|
|
|
6,522
|
|
|
|
(5,044
|
)
|
Prepaid expenses and other assets
|
|
|
227
|
|
|
|
(729
|
)
|
|
|
(187
|
)
|
Accounts payable
|
|
|
855
|
|
|
|
(12,597
|
)
|
|
|
8,546
|
|
Revenue payable
|
|
|
423
|
|
|
|
(1,171
|
)
|
|
|
(494
|
)
|
Accrued liabilities
|
|
|
1,771
|
|
|
|
(842
|
)
|
|
|
(969
|
)
|
Other
|
|
|
103
|
|
|
|
(21
|
)
|
|
|
128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
20,288
|
|
|
|
12,672
|
|
|
|
32,838
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of oil and natural gas properties
|
|
|
(104,542
|
)
|
|
|
(17,455
|
)
|
|
|
(15,199
|
)
|
Additions to oil and gas properties
|
|
|
(13,129
|
)
|
|
|
(19,034
|
)
|
|
|
(45,378
|
)
|
Additions to other property and equipment
|
|
|
(416
|
)
|
|
|
(210
|
)
|
|
|
(388
|
)
|
Proceeds from the sale of oil and gas properties
|
|
|
1,400
|
|
|
|
11,752
|
|
|
|
15,418
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities
|
|
|
(116,687
|
)
|
|
|
(24,947
|
)
|
|
|
(45,547
|
)
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Advances on revolving credit facility
|
|
|
115,106
|
|
|
|
11,948
|
|
|
|
24,570
|
|
Payments on revolving credit facility
|
|
|
(61,600
|
)
|
|
|
(12,749
|
)
|
|
|
(8,750
|
)
|
Contributed capital
|
|
|
44,130
|
|
|
|
17,306
|
|
|
|
|
|
Distribution to partners
|
|
|
|
|
|
|
|
|
|
|
(4,191
|
)
|
Proceeds from borrowings of long-term debt
|
|
|
182
|
|
|
|
|
|
|
|
|
|
Repayment of borrowings of long-term debt
|
|
|
(44
|
)
|
|
|
(27
|
)
|
|
|
(10
|
)
|
Loan origination fees
|
|
|
(1,018
|
)
|
|
|
(489
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
$
|
96,756
|
|
|
$
|
15,989
|
|
|
$
|
11,619
|
|
Net increase (decrease) in cash
|
|
|
357
|
|
|
|
3,714
|
|
|
|
(1,090
|
)
|
Cash and cash equivalents, beginning of year
|
|
$
|
5,297
|
|
|
$
|
1,583
|
|
|
$
|
2,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of year
|
|
$
|
5,654
|
|
|
$
|
5,297
|
|
|
$
|
1,583
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
4,309
|
|
|
$
|
2,677
|
|
|
$
|
2,087
|
|
Noncash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of fixed assets with note payable
|
|
|
|
|
|
|
117
|
|
|
|
|
|
Environmental remediation net liability recorded as part of
Merit acquisition (see Note 3)
|
|
|
1,450
|
|
|
|
|
|
|
|
|
|
See accompanying notes to combined financial statements.
F-42
PREDECESSOR
General
Memorial Production Partners LP (the Partnership) is
a limited partnership formed in April 2011 by Memorial Resource
Development LLC (Memorial Resource) to acquire,
develop and produce oil and natural gas properties and to
acquire, own and operate related assets. Memorial Resource,
which is owned by Natural Gas Partners VIII, L.P. (NGP
VIII) and Natural Gas Partners IX, L.P., currently owns
all the general and limited partner interests in the
Partnership. The Partnership plans to pursue an initial public
offering of its common units representing limited partner
interests (the Offering). In connection with the
closing of the Offering, pursuant to a planned contribution,
conveyance and assignment agreement, the Partnership will
acquire for a combination of cash and common units
(1) substantially all of the oil and natural gas properties
and related assets currently owned by BlueStone Natural
Resources, LLC, a majority-controlled subsidiary of Memorial
Resource, (2) certain oil and natural gas properties and
related assets currently owned by Classic Hydrocarbons Holdings,
L.P., a majority-controlled subsidiary of Memorial Resource, and
(3) certain oil and natural gas properties and related
assets currently controlled by WHT Energy Partners LLC
(WHT), which is 50% owned by WildHorse Resources,
LLC and 50% owned by Tanos Energy, LLC, both of which are
majority-controlled subsidiaries of Memorial Resource. The
assets were acquired by WHT in April 2011.
The following entities were determined in accordance with the
rules and regulations of the U.S. Securities and Exchange
Commission to represent the combined predecessor (the
Predecessor) of the Partnership.
|
|
|
|
|
BlueStone Natural Resources, LLC (BlueStone) is a
Delaware limited liability company formed in January 2006 to
engage in the acquisition, development, production and
exploration and sale of oil and natural gas. BlueStone is a
wholly owned subsidiary of BlueStone Natural Resources Holdings,
LLC (Holdings), whose sole purpose is to provide
financing for BlueStone. BlueStone owns oil and natural gas
producing properties in Texas. Prior to the Offering, Memorial
Resource owned an 89.45% interest in BlueStone and certain
members of BlueStones management owned a 10.55% interest.
|
|
|
|
Certain carved-out oil and natural gas properties (Classic
Carve-Out) of Classic Hydrocarbons Holdings, L.P,
(Classic) that will be acquired by the Partnership
at the closing of the initial public offering. Classic was
formed in 2006 to engage in the exploration, development,
production, and sale of oil and natural gas primarily in East
Texas. Prior to the Offering, Memorial Resource owned a 90.21%
limited partner interest in Classic and an 83.33% membership
interest in the general partner of Classic.
|
The Classic Carve-Out financial statements include the
applicable amounts of Craton Energy Holdings, III
(Craton), which was contributed to Classic by NGP
VIII in 2009. This contribution was accounted for as a
combination of entities under common control; therefore, Classic
accounted for the acquisition in a manner similar to the pooling
of interest method. Information included in these financial
statements is presented as if Craton had been combined
throughout the periods presented in which common control existed.
|
|
Note 2
|
Basis of
Presentation and Significant Accounting Policies
|
|
|
(a)
|
Basis
of Presentation
|
The accompanying combined financial statements were derived from
the historical accounting records of the Predecessor and reflect
the historical financial position, results of operations and
cash flows for the periods described herein. All material
intercompany transactions and account balances have been
eliminated in the combination of accounts. The accompanying
combined financial statements have been prepared in accordance
with accounting principles generally accepted in the United
States of America (GAAP). The Predecessor operates
oil and natural gas properties as one business segment: the
exploration, development and production
F-43
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
of oil and natural gas. The Predecessors management
evaluates performance based on one business segment as there are
not different economic environments within the operation of the
oil and natural gas properties.
As common control exists among the Predecessor entities, the
Predecessors combined financial statements reflect the
financial statements of BlueStone and Classic Carve-Out on a
combined basis for the periods presented.
The Classic Carve-Out amounts included in the accompanying
financial statements were determined in accordance with
Regulations S-X, Article 3 General instructions as
to financial statements and Staff Accounting Bulletin
(SAB) Topic 1-B Allocations of Expenses and
Related Disclosure in Financial Statements of Subsidiaries,
Divisions or Lesser Business Components of Another
Entity. Certain expenses incurred by Classic are only
indirectly attributable to its ownership of Classic Carve-Out as
Classic owns interests in numerous other oil and natural gas
properties. As a result, certain assumptions and estimates were
made in order to allocate a reasonable share of such expenses to
the Predecessor, so that the amounts included in the
accompanying combined financial statements attributable to
Predecessor reflect substantially all of the cost of doing
business. Such allocations may or may not reflect future costs
associated with the operation of the Partnership.
The preparation of combined financial statements in conformity
with GAAP requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the combined financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Significant estimates include, but are not limited to, oil and
natural gas reserves; depreciation, depletion, and amortization
of proved oil and natural gas properties; future cash flows from
oil and natural gas properties; impairment of long-lived assets;
fair value of derivatives; fair value of equity compensation;
fair values of assets acquired and liabilities assumed in
business combinations and asset retirement obligations.
|
|
(c)
|
Principles
of Combination
|
The accompanying combined financial statements include the
accounts of BlueStone and its wholly owned subsidiaries as well
as the accounts of Classic Carve-Out. All material intercompany
balances and transactions have been eliminated.
|
|
(d)
|
Cash
and Cash Equivalents
|
The Predecessor considers all highly liquid instruments with
original contractual maturities of three months or less to be
cash equivalents.
|
|
(e)
|
Concentrations
of Credit Risk and Significant Customers
|
Financial instruments which potentially subject the Predecessor
to credit risk consist principally of cash balances, accounts
receivable and derivative financial instruments. The Predecessor
maintains cash and cash equivalents in bank deposit accounts
which, at times, may exceed the federally insured limits.
Management periodically reviews and assesses the financial
condition of the banks to mitigate the risk of loss. Derivative
financial instruments are generally executed with major
financial institutions that expose the Predecessor to market and
credit risks and which may, at times, be concentrated with
certain counterparties. The credit worthiness of the
counterparties is subject to continual review. The Predecessor
also has netting arrangements in place with counterparties to
reduce credit exposure. The Predecessor has not experienced any
losses from such investments.
F-44
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
The Predecessors oil and natural gas sales are to a
variety of purchasers, including intrastate and interstate
pipelines or their marketing affiliates and independent
marketing companies. The Predecessors joint operations
account receivables are from a number of oil and natural gas
companies, partnerships, individuals, and others who own
interests in the properties operated by the Predecessor.
Generally, operators of crude oil and natural gas properties
have the right to offset future revenues against unpaid charges
related to operated wells, minimizing the credit risk associated
with these receivables. Additionally, management believes that
any credit risk imposed by a concentration in the oil and
natural gas industry is offset by the creditworthiness of the
Predecessors customer base. Management determines amounts
to be uncollectible when the Predecessor has used all reasonable
means of collection and settlement. Amounts outstanding longer
than the contractual terms are considered past due. Management
believes all amounts included in accounts receivable at
December 31, 2010 and 2009 will be collected, and
therefore, no allowance for uncollectible accounts has been
recorded.
For the year ended December 31, 2010, purchases by
Enterprise Texas Pipeline, LLC, Dominion Gas Ventures, LP and
ConocoPhillips accounted for 30.5%, 24.9% and 11.2%,
respectively, of the Predecessors total sales revenues.
For the year ended December 31, 2009, purchases by
Enterprise Texas Pipeline, LLC and Dominion Gas Ventures, LP
accounted for 35.8% and 34.4%, respectively, of the
Predecessors total sales revenues.
For the year ended December 31, 2008, purchases by Dominion
Gas Ventures, LP and Enterprise Texas Pipeline, LLC accounted
for 43.4% and 31.5%, respectively, of the Predecessors
total sales revenues. No other customer accounted for more than
10% of total revenues for the years ended December 31,
2010, 2009, or 2008.
If the Predecessor were to lose any one of its customers, the
loss could temporarily delay production and sale of oil and
natural gas in the related producing region. If the Predecessor
were to lose any single customer, the Predecessor believes that
a substitute customer to purchase the impacted production
volumes could be identified. However, if one or more of the
Predecessors larger customers ceased purchasing oil or
natural gas altogether, the loss of such customer could have a
detrimental effect on production volumes in general and on the
ability to find substitute customers to purchase production
volumes.
|
|
(f)
|
Oil
and Natural Gas Properties
|
The Predecessor accounts for its oil and natural gas
exploration, development and production activities in accordance
with the successful efforts method of accounting. Under this
method, costs of acquiring properties, costs of drilling
successful exploration wells, and development costs are
capitalized. The costs of exploratory wells are initially
capitalized pending a determination of whether proved reserves
have been found. At the completion of drilling activities, the
costs of exploratory wells remain capitalized if determination
is made that proved reserves have been found. If no proved
reserves have been found, the costs of each of the related
exploratory wells are charged to expense. In some cases, a
determination of proved reserves cannot be made at the
completion of drilling, requiring additional testing and
evaluation of the wells. The Predecessors policy is to
expense the costs of such exploratory wells if a determination
of proved reserves has not been made within a twelve-month
period after drilling is complete. Exploration costs such as
geological, geophysical, and seismic costs are expensed as
incurred.
As exploration and development work progresses and the reserves
on these properties are proven, capitalized costs attributed to
the properties are subject to depreciation and depletion.
Depletion of capitalized costs is provided using the
units-of-production
method based on proved oil and gas reserves related to the
associated field. The timing of any write downs of unproven
properties, if warranted, depends upon the nature, timing, and
extent of planned exploration and development activities and
their results.
F-45
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
On the sale or retirement of a complete or partial unit of a
proved property or pipeline and related facilities, the cost and
related accumulated depreciation, depletion, and amortization
are eliminated from the property accounts, and any gain or loss
is recognized.
The following table presents the amount of capitalized
exploratory drilling costs pending evaluation at December 31 for
each of the last three years and changes in those amounts during
the years then ended (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Balance, January 1
|
|
$
|
821
|
|
|
$
|
1,468
|
|
|
$
|
124
|
|
Additions to capitalized exploratory well costs pending
determination of proved reserves
|
|
|
2,013
|
|
|
|
821
|
|
|
|
1,468
|
|
Reclassification to proved oil and natural gas properties based
on the determination of proved reserves
|
|
|
(821
|
)
|
|
|
|
|
|
|
(124
|
)
|
Capitalized exploratory well costs charged to expense
|
|
|
|
|
|
|
(1,468
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31
|
|
$
|
2,013
|
|
|
$
|
821
|
|
|
$
|
1,468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The estimates of proved oil and natural gas reserves utilized in
the preparation of the combined financial statements are
estimated in accordance with the guidelines established by the
Securities and Exchange Commission (SEC) and the Financial
Accounting Standards Board (FASB), which subsequent to
December 31, 2008 require that reserve estimates be
prepared under existing economic and operating conditions using
a 12-month
average price with no provision for price and cost escalations
in future years except by contractual arrangements. The
Predecessors annual reserve estimates were prepared by
third-party petroleum engineers.
Reserve estimates are inherently imprecise. Accordingly, the
estimates are expected to change as more current information
becomes available. The Predecessor depletes its oil and gas
properties by field using the
units-of-production
method. Capitalized drilling and development costs of producing
oil and natural gas properties are depleted over proved
developed reserves and leasehold costs are depleted over total
proved reserves. It is possible that, because of changes in
market conditions or the inherent imprecision of reserve
estimates, the estimates of future cash inflows, future gross
revenues, the amount of oil and natural gas reserves, the
remaining estimated lives of oil and natural gas properties, or
any combination of the above may be increased or reduced.
Increases in recoverable economic volumes generally reduce per
unit depletion rates while decreases in recoverable economic
volumes generally increase per unit depletion rates.
In January 2010, the FASB issued Accounting Standards Update
2010-03
(ASU
2010-03),
Oil and Gas Reserve Estimations and Disclosures. This
update aligns the current oil and natural gas reserve estimation
and disclosure requirements of ASC Topic 932, Extractive
Activities Oil and Gas, with the requirements in
the Securities and Exchange Commissions final rule,
Modernization of Oil and Gas Reporting Requirements (the
Final Rule), which was issued on December 31,
2008 and was effective for the year ended December 31,
2009. The Final Rule was designed to modernize and update the
oil and natural gas disclosure requirements to align with
current practices and changes in technology.
The Final Rule permits the use of new technologies to determine
proved reserves estimates if those technologies have been
demonstrated empirically to lead to reliable conclusions about
reserve volume estimates. The Final Rule will also allow, but
not require, companies to disclose their probable and possible
reserves to investors. In addition, the new disclosure
requirements require companies to: (i) report the
independence and qualifications of its reserves preparer or
auditor; (ii) file reports when a third party is relied
upon to prepare reserves estimates or conduct a reserves audit;
and (iii) report oil and natural gas reserves
F-46
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
using an average price based upon the prior
12-month
period rather than a year-end price. The Final Rule became
effective for fiscal years ending on or after December 31,
2009. The Predecessors 2009 and 2010 depletion
calculations were based upon proved reserves that were
determined using the new reserve rules; whereas, the depletion
calculation in 2008 was based on the prior SEC methodology.
|
|
(h)
|
Other
Property and Equipment
|
Other property and equipment is stated at historical costs and
is comprised primarily of vehicles, furniture, fixtures, and
computer hardware and software. Depreciation of other property
and equipment is calculated using the straight-line method based
on estimated useful lives of three to five years.
Proved oil and natural gas properties are reviewed for
impairment when events and circumstances indicate a possible
decline in the recoverability of the carrying value of such
properties, such as a downward revision of the reserve
estimates, less than expected production, drilling results, or
lower commodity prices. The estimated future cash flows expected
in connection with the property are compared to the carrying
value of the property to determine if the carrying amount is
recoverable. If the carrying value of the property exceeds its
estimated undiscounted future cash flows, the carrying amount of
the property is reduced to its estimated fair value. The factors
used to determine fair value include, but are not limited to,
estimates of proved reserves, future commodity prices, the
timing of future production and capital expenditures and a
discount rate commensurate with the risk reflective of the lives
remaining for the respective oil and gas properties. The
Predecessor accounts for impairment as a Level 3 fair value
computation. Impairment expense for the years ended
December 31, 2010, 2009 and 2008 was approximately
$11.8 million, $3.5 million and $14.2 million.
Nonproducing oil and natural gas properties, which consist of
undeveloped leasehold costs and costs associated with the
purchase of proved undeveloped reserves, are assessed for
impairment on a
property-by-property
basis. If the assessment indicates an impairment, a loss is
recognized by providing a valuation allowance. The impairment
assessment is affected by economic factors such as the results
of exploration activities, commodity price outlooks, remaining
lease terms, and potential shifts in business strategy employed
by management.
|
|
(j)
|
Asset
Retirement Obligations
|
The Predecessor accounts for asset retirement obligations under
ASC Topic 410, Asset Retirement and Environmental
Obligations. ASC 410 requires legal obligations
associated with the retirement of long-lived assets to be
recognized at their fair value at the time that the obligations
are incurred. Oil and gas producing companies incur such a
liability upon acquiring or drilling a well. Under ASC 410,
an asset retirement obligation is recorded as a liability at its
estimated present value at the assets inception, with an
offsetting increase to producing properties in the accompanying
combined balance sheets, which is allocated to expense over the
useful life of the asset. Periodic accretion of the discount on
asset retirement obligations is recorded as an expense in the
accompanying combined statements of operations. Upon settlement
of the liability, a gain or loss is recognized to the extent the
actual costs differ from the recorded liability. See Note 6.
|
|
(k)
|
Other
Long-Term Assets
|
Other long-term assets consist of deposits and deferred
financing costs associated with the Predecessors credit
facilities. Deferred financing costs are stated at cost, net of
amortization, and are amortized over the terms of the credit
facilities. Amortization expense for the years ended
December 31, 2010, 2009, and 2008 was approximately
$745,000, $109,000, and $26,000, respectively.
F-47
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
Oil and natural gas revenues are recorded using the sales
method. Under this method, the Predecessor recognizes revenues
based on actual volumes of oil and natural gas sold to
purchasers. The Predecessor and other joint interest owners may
sell more or less than their entitlement share of volumes
produced. A liability is recorded and revenue is deferred if the
Predecessors excess sales of natural gas volumes exceed
its estimated remaining recoverable reserves. The Predecessor
had no significant natural gas imbalances at December 31,
2010 or 2009.
|
|
(m)
|
General
and Administrative Expense
|
The Predecessor receives fees for operation of jointly owned oil
and natural gas properties and records such reimbursements as a
reduction of general and administrative expenses. Such fees
totaled approximately $980,000, $858,000 and $899,000 for the
years ended December 31, 2010, 2009, and 2008, respectively.
|
|
(n)
|
Derivative
Instruments
|
The Predecessor uses derivative financial instruments (swaps,
floors, collars, and forward sales) to reduce the impact of
natural gas and oil price fluctuations and uses interest rate
swaps to manage exposure to interest rate volatility, primarily
as a result of variable rate borrowings under the credit
facilities. Every derivative instrument (including certain
derivative instruments embedded in other contracts) is recorded
in the balance sheet as either an asset or liability measured at
its fair value. Changes in the derivatives fair value are
recognized currently in earnings unless specific hedge
accounting criteria are met. Special accounting for qualifying
hedges allows a derivatives gains and losses to offset
related results on the hedged item in the statements of
operations. Companies must formally document, designate, and
assess the effectiveness of transactions that receive hedge
accounting treatment. The Predecessor had no derivatives
designated as hedges at December 31, 2010 or 2009.
Changes in the fair value of derivative financial instruments
that do not qualify for accounting treatment as hedges are
recognized currently in the statements of operations.
The Predecessors entities are not taxpaying entities for
federal income tax purposes, and thus no federal income tax
expense has been recorded in the accompanying combined financial
statements. The partners or members of the Predecessors
entities are responsible for federal income taxes on their
respective share of the Predecessors entities income.
The Predecessors entities are subject to the Texas margin
tax and certain aspects of the tax make it similar to an income
tax as the tax is assessed on 1% of taxable margin. Deferred
taxes related to Texas margin tax arise due to temporary
differences between the financial statement carrying value of
existing assets and liabilities and their respective tax basis.
Deferred tax liabilities and current tax expense as of and for
the year ended December 31, 2010 was approximately
$225,000. There were no deferred taxes at December 31, 2009
and no tax expense recorded for the years ending
December 31, 2009 and 2008. The Predecessor had no
uncertain tax positions that required recognition in the
combined financial statements at December 31, 2010 or 2009.
The cost of employee services received in exchange for equity
instruments is measured based on estimated fair value at period
end for liability awards. That cost is recognized as
compensation expense over the requisite service period. Awards
subject to performance criteria vest when it is probable that
the
F-48
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
performance criteria will be met and the requisite service
period has been met. Generally, no compensation expense is
recognized for equity instruments that do not vest.
|
|
(q)
|
New
Accounting Pronouncements
|
On July 21, 2010, the FASB issued ASU
2010-20
Receivables (Topic 310) Disclosures about the
Credit Quality of Financial Receivables and the Allowance for
Credit Losses. ASU
2010-20
requires disclosure of additional information to assist
financial statement users to understand more clearly an
entitys credit risk exposures to finance receivables and
the related allowance for credit losses. ASU
2010-20 is
effective for all public companies for interim and annual
reporting periods ending on or after December 15, 2010,
with specific items, such as the allowance rollforward and
modification disclosures, effective for periods beginning after
December 15, 2010. We do not expect the adoption of this
new guidance to have an impact on our financial position, cash
flows or results of operations.
In April 2010, the FASB issued ASU
2010-14,
which amends the guidance on oil and natural gas reporting in
Accounting Standards Codification 932.10.S99-1 by adding the
Codification of SEC
Regulation S-X,
Rule 4-10
as amended by the SEC Final
Rule 33-8995.
Both ASU
2010-03 and
ASU 2010-14
are effective for annual reporting periods ending on or after
December 31, 2009. Application of the revised rules is
prospective and companies are not required to change prior
period presentation to conform to the amendments.
In January 2010, the FASB issued Accounting Standards Update
(ASU)
2010-06,
Fair Value Measurements and Disclosures (Topic 820): Improving
Disclosures about Fair Value Measurements. ASU
2010-06
requires reporting entities to provide information about
movements of assets amount Levels 1 and 2 of the three-tier
fair value hierarchy established by FASB ASC 820. The
guidance is effective for any fiscal year that begins after
December 15, 2009. The Predecessor adopted the provisions
of ASU
2010-06 on
January 1, 2010 and this ASU did not have a material impact
on the Predecessors financial position, results of
operations or cash flows.
|
|
Note 3
|
Acquisitions
and Divestitures
|
The Predecessor acquires proved oil and natural gas properties
that meet managements criteria with respect to reserve
lives, development potential, production risk and other
operational characteristics. The Predecessor generally does not
acquire assets other than oil and natural gas property interests.
The operating revenues and expenses of acquired properties are
included in the Predecessors combined financial statements
from their respective closing dates forward. Transactions are
financed through partner contributions and borrowings.
The acquisitions discussed below were accounted for under the
acquisition method of accounting. Accordingly, the Predecessor
conducted assessments of net assets acquired and recognized
amounts for identifiable assets acquired and liabilities assumed
at their estimated acquisition date fair values, while
acquisition costs associated with the acquisitions were expensed
as incurred for 2010 and 2009 and were capitalized as additional
costs of oil and natural gas properties for 2008.
The fair values of oil and natural gas properties are measured
using valuation techniques that convert future cash flows to a
single discounted amount. Significant inputs to the valuation of
oil and natural properties include estimates of:
(i) reserves; (ii) future operating and development
costs; (iii) future commodity prices; and (iv) a
market-based weighted average cost of capital rate.
F-49
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
2010
Acquisitions
Effective January 1, 2010, the Predecessor acquired
producing oil and natural gas properties in East Texas from
Petrohawk Properties, LP for approximately $5.8 million.
The net purchase price was allocated $5.8 million to proved
oil and gas properties. The acquisition closed on May 28,
2010.
Effective March 1, 2010, the Predecessor acquired oil and
natural gas properties in East Texas from BP America Production
Company for approximately $8.2 million. The net purchase
price was allocated to proved oil and gas properties. This
acquisition closed on March 29, 2010.
Effective April 1, 2010, the Predecessor acquired Forest
Oils interests in wells located in Webb County, Texas (the
Forest Oil Properties) for a net purchase price of
approximately $65.9 million. The net purchase price was
allocated to oil and gas properties. This acquisition of
properties closed on June 30, 2010.
Summarized below are the results of operations for the years
ended December 31, 2010 and 2009, on an unaudited pro forma
basis, as if the acquisition had occurred on January 1,
2009. The unaudited pro forma financial information was derived
from the historical combined statement of operations of the
Predecessor and the statements of revenues and direct operating
expenses for the Forest Oil Properties, which were derived from
the historical accounting records of the seller. The unaudited
pro forma financial information does not purport to be
indicative of results of operations that would have occurred had
the transaction occurred on the basis assumed above, nor is such
information indicative of the Predecessors expected future
results of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
2009
|
|
|
Actual
|
|
Pro Forma
|
|
Actual
|
|
Pro Forma
|
|
|
(In thousands)
|
|
(In thousands)
|
|
Forest Oil Properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
38,741
|
|
|
$
|
47,409
|
|
|
$
|
24,860
|
|
|
$
|
41,131
|
|
Net (loss) income
|
|
$
|
(11,317
|
)
|
|
$
|
(5,506
|
)
|
|
$
|
1,106
|
|
|
$
|
11,631
|
|
Effective May 1, 2010, the Predecessor acquired Merit
Energys (Merit) interest in wells located in
South Texas for a net purchase price of approximately
$14.1 million. The net purchase price was allocated as
follows (in thousands):
|
|
|
|
|
Oil and gas properties
|
|
$
|
15,397
|
|
Prepaid assets
|
|
|
450
|
|
Assumed liabilities
|
|
|
(1,728
|
)
|
|
|
|
|
|
Net purchase price
|
|
$
|
14,119
|
|
|
|
|
|
|
As part of the acquisition process, an environmental review was
performed and it was determined that there was environmental
damage to one of the acquired properties. As such, the parties
agreed to reduce the purchase price by $550,000. Additionally,
the Predecessor and Merit entered into an escrow agreement where
the Predecessor agreed to pay for the initial $1.0 million
of the remediation costs, with Merit paying for gross amounts
incurred in excess of $1.0 million and up to
$1.45 million. The Predecessors anticipated cost to
remediate this area is $1.45 million. As of
December 31, 2010, the Predecessor has recorded an accrued
liability of $1.45 million for these remediation costs.
Merit has funded an escrow account with the $450,000 and that
amount is included in the balance sheet as a prepaid asset. This
acquisition closed on June 4, 2010.
Effective May 1, 2010, the Predecessor acquired Zachry
Exploration, LLCs interest in the Predecessors
Laredo area properties for a net purchase price of
$6.5 million. The net purchase price was allocated to oil
and gas properties. This acquisition closed on August 3,
2010.
F-50
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
Effective April 1, 2010, the Predecessor acquired
U.S. Enercorp, LTDs interest in wells located in
McMullen County, Texas for a net purchase price of approximately
$2.6 million. The net purchase price was allocated to oil
and gas properties. This acquisition closed on May 28, 2010.
The Predecessor also acquired interests in oil and gas
properties in a number of individually insignificant
acquisitions during 2010 which aggregated to a total of
approximately $6.0 million. Included in other expense in
the accompanying combined statements of operations for the year
ended December 31, 2010 are approximately $890,000 of
acquisition costs related to the 2010 acquisitions.
2009
Acquisitions
Effective February 1, 2009, the Predecessor acquired
Coronado Energy E&P Company, LLCs interest in
Predecessors Laredo area properties for a net purchase
price of approximately $13.0 million. The net purchase
price was allocated to oil and gas properties. This acquisition
closed on March 16, 2009.
The Predecessor acquired Chroma Oil and Gas, LPs interest
in the Predecessors Laredo area properties, effective
April 1, 2009 for a net purchase price of approximately
$2.9 million. The net purchase price was allocated to oil
and gas properties. The acquisition closed on May 20, 2009.
The Predecessor also acquired interests in oil and gas
properties in a number of individually insignificant
acquisitions during 2009, which aggregated to a total of
approximately $0.9 million. Included in other expense in
the accompanying combined statements of operations for the year
ended December 31, 2009 are approximately $304,000 of
acquisition costs related to the 2009 acquisitions.
2008
Acquisitions
Effective April 1, 2008, the Predecessor acquired Forest
Energys interest in the Predecessors Laredo area
properties for a net purchase price of approximately
$8.7 million. The acquisition closed on April 22,
2008. Effective September 1, 2008, the Predecessor acquired
additional oil and gas properties from Forest for a net purchase
price of approximately $6.0 million. The acquisition closed
on October 6, 2008. The net purchase price of these
acquisitions was allocated to oil and gas properties. In
addition, the Predecessor obtained Chevrons working
interest in undeveloped acreage in the Laredo area properties
for approximately $0.8 million through a farm-out agreement.
Divestitures
of non-core assets
On January 20, 2010, the Predecessor sold its interests in
the Saner wells for net proceeds of approximately
$1.4 million. There was no significant gain or loss
associated with this sale. In addition, during 2010, the
Predecessor received a settlement of approximately
$1.2 million related to a property that the Predecessor had
not been given the opportunity to acquire despite a preferential
right to acquire the property held by the Predecessor. This
settlement amount has been recorded in other income for the year
ended December 31, 2010.
Effective January 8, 2009, the Predecessor sold a portion
of their interests in the Nueces Mineral Company lease (NMC
Lease) for net proceeds of $2.7 million. The Predecessor
sold additional interests in the NMC Lease effective May 1,
2009 for net proceeds of $9.0 million. The Predecessor
recorded gains on these sales of approximately $7.8 million.
Effective January 1, 2008, the Predecessor sold their Rocky
Mountain assets for $8.0 million. The Predecessor recorded
a gain on this sale of approximately $3.9 million.
On February 28, 2008, the Predecessor sold their
Mid-Continent assets at auction for proceeds of approximately
$0.4 million. The Predecessor recorded a gain on this sale
of approximately $0.1 million.
F-51
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
Effective June 1, 2008, the Predecessor sold their
interests in Harris County for net proceeds of approximately
$6.7 million. The Predecessor recorded a gain on this sale
of approximately $3.0 million.
|
|
Note 4
|
Fair
Value Measurements of Financial Instruments
|
The Predecessor uses a valuation framework based upon inputs
that market participants use in pricing an asset or liability,
which are classified into two categories: observable inputs and
unobservable inputs. Observable inputs represent market data
obtained from independent sources; whereas, unobservable inputs
reflect a companys own market assumptions, which are used
if observable inputs are not reasonably available without undue
cost and effort. These two types of inputs are further divided
into the following fair value input hierarchy:
Level 1 Unadjusted quoted prices
in active markets that are accessible at the measurement date
for identical, unrestricted assets or liabilities. The
Predecessor considers active markets to be those in which
transactions for the assets or liabilities occur in sufficient
frequency and volume to provide pricing information on an
ongoing basis.
Level 2 Quoted prices in markets
that are not active, or inputs that are observable, either
directly or indirectly, for substantially the full term of the
asset or liability. This category includes those derivative
instruments that the Predecessor values using observable market
data. Substantially all of these inputs are observable in the
marketplace throughout the full term of the derivative
instrument, can be derived from observable data, or are
supported by observable levels at which transactions are
executed in the marketplace. Level 2 instruments primarily
include non-exchange-traded derivatives, such as
over-the-counter
commodity price swaps, collars, put options and interest rate
swaps. At December 31, 2010 and 2009, all of the
Predecessors derivative instruments were considered
Level 2.
Level 3 Measure based on prices
or valuation models that require inputs that are both
significant to the fair value measurement and are less
observable from objective sources (i.e., supported by little or
no market activity).
Assets
and Liabilities Measured at Fair Value on a Recurring
Basis
The carrying values of cash and cash equivalents, accounts
receivables, accounts payables (including accrued liabilities)
and amounts outstanding under long-term debt agreements included
in the accompanying combined balance sheets approximated fair
value at December 31, 2010 and 2009. These assets and
liabilities are not presented in the following tables.
Derivative Instruments The fair market
values of the derivative financial instruments reflected in the
combined balance sheets were based on quotes obtained from the
counterparties to the agreements. Financial assets and
liabilities are classified based on the lowest level of input
that is significant to the fair value measurement. The
Predecessors assessment of the significance of a
particular input to the fair value measurement requires
judgment, and may affect the valuation of the fair value of
assets and liabilities and their placement within the fair value
hierarchy levels.
The fair value input hierarchy to which an asset or liability
measurement falls is determined based on the lowest-level input
that is significant to the measurement in its entirety. The
following table presents the
F-52
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
Predecessors assets and liabilities that are measured at
fair value on a recurring basis at December 31, 2010 and
2009 for each of the fair value hierarchy levels (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2010 Using
|
|
|
|
Quoted Prices in
|
|
|
Significant Other
|
|
|
Significant
|
|
|
Fair Value at
|
|
|
|
Active Markets
|
|
|
Observable Inputs
|
|
|
Unobservable Inputs
|
|
|
December 31,
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
2010
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
$
|
|
|
|
$
|
3,067
|
|
|
$
|
|
|
|
$
|
3,067
|
|
Commodity derivative collar contracts
|
|
|
|
|
|
|
4,086
|
|
|
|
|
|
|
|
4,086
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
|
|
|
$
|
7,153
|
|
|
$
|
|
|
|
$
|
7,153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price collar contracts
|
|
$
|
|
|
|
$
|
(420
|
)
|
|
$
|
|
|
|
$
|
(420
|
)
|
Commodity derivative put options
|
|
|
|
|
|
|
(58
|
)
|
|
|
|
|
|
|
(58
|
)
|
Commodity derivative interest rate swaps
|
|
|
|
|
|
|
(403
|
)
|
|
|
|
|
|
|
(403
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
|
|
|
$
|
(881
|
)
|
|
$
|
|
|
|
$
|
(881
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2009 Using
|
|
|
|
Quoted Prices in
|
|
|
Significant Other
|
|
|
Significant
|
|
|
|
|
|
|
Active Markets
|
|
|
Observable Inputs
|
|
|
Unobservable Inputs
|
|
|
Fair Value at
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
December 31, 2009
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
$
|
|
|
|
$
|
1,683
|
|
|
$
|
|
|
|
$
|
1,683
|
|
Commodity derivative collar contracts
|
|
|
|
|
|
|
2,264
|
|
|
|
|
|
|
|
2,264
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
|
|
|
$
|
3,947
|
|
|
$
|
|
|
|
$
|
3,947
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative price swap contracts
|
|
$
|
|
|
|
$
|
(104
|
)
|
|
$
|
|
|
|
$
|
(104
|
)
|
Commodity derivative price collar contracts
|
|
|
|
|
|
|
(137
|
)
|
|
|
|
|
|
|
(137
|
)
|
Commodity derivative interest rate swaps
|
|
|
|
|
|
|
(107
|
)
|
|
|
|
|
|
|
(107
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
|
|
|
$
|
(348
|
)
|
|
$
|
|
|
|
$
|
(348
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For additional information on the Predecessors derivative
instruments, see note 5.
F-53
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
Assets
and Liabilities Measured at Fair Value on a Nonrecurring
Basis:
Certain assets and liabilities are reported at fair value on a
nonrecurring basis in the Predecessors combined balance
sheets. The following methods and assumptions were used to
estimate the fair values:
Asset Retirement Obligations
(AROs) The Predecessor estimates the
fair value of AROs based on discounted cash flow
projections using numerous estimates, assumptions, and judgments
regarding such factors as the existence of a legal obligation
for an ARO; amounts and timing of settlements; the
credit-adjusted risk-free rate to be used; and inflation rates.
See note 6 for a summary of changes in AROs.
Properties Acquired in Business
Combinations If sufficient market data is
not available, the Predecessor determines the fair values of
proved and unproved properties acquired in transactions
accounted for as business combinations by preparing estimates of
discounted cash flow projections. The factors to determine fair
value include, but are not limited to, estimates of proved
reserves, future commodity prices, the timing of future
production and capital expenditures and a discount rate
commensurate with the risk reflective of the lives remaining for
the respective oil and gas properties.
|
|
Note 5
|
Risk
Management and Derivative Instruments
|
The Predecessor utilizes derivative instruments to manage
exposure to commodity price and interest rate fluctuations and
achieve a more predictable cash flow in connection with its
natural gas and oil sales from production and borrowing related
activities. These transactions limit exposure to declines in
prices or increases in interest rates, but also limit the
benefits the Predecessor would realize if prices increase or
interest rates decrease.
Inherent in the Predecessors portfolio of natural gas and
interest rate derivative contracts are certain business risks,
including market risk and credit risk. Market risk is the risk
that the price of natural gas will change, either favorably or
unfavorably, in response to changing market conditions. Credit
risk is the risk of loss from nonperformance by the
Predecessors counterparty to a contract. The Predecessor
does not require collateral from its counterparties but does
attempt to minimize its credit risk associated with derivative
instruments by limiting its exposure to any single counterparty
and entering into derivative instruments only with
counterparties that are large financial institutions, which
management believes present minimal credit risk. In addition, to
mitigate its risk of loss due to default, the Predecessor has
entered into master netting agreements with its counterparties
on its derivative instruments that allow the Predecessor to
offset its asset position with its liability position in the
event of default by the counterparty. Had the Predecessors
counterparties failed to perform under existing derivative
contracts, the maximum loss at December 31, 2010 would be
approximately $6,080,000.
|
|
(a)
|
Commodity
Derivatives
|
The Predecessor uses a combination of natural gas swaps,
costless collars and put options to manage its exposure to
commodity price volatility. At December 31, 2010, the
Predecessor had the following open commodity positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Swaps
|
|
|
|
|
Average Monthly
|
|
Weighted Average
|
Beginning Month
|
|
Ending Month
|
|
Volumes (MMBtu)
|
|
Fixed Price
|
|
|
1/1/2011
|
|
|
|
12/31/2011
|
|
|
|
88,000
|
|
|
$
|
6.11
|
|
|
2/1/2011
|
|
|
|
6/30/2011
|
|
|
|
54,000
|
|
|
$
|
4.10
|
|
|
1/1/2012
|
|
|
|
6/30/2012
|
|
|
|
15,000
|
|
|
$
|
5.35
|
|
|
1/1/2012
|
|
|
|
12/31/2012
|
|
|
|
90,000
|
|
|
$
|
5.81
|
|
|
1/1/2013
|
|
|
|
12/31/2013
|
|
|
|
61,000
|
|
|
$
|
5.76
|
|
F-54
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Collars
|
|
|
|
|
Average Monthly
|
|
Weighted Average
|
|
Weighted Average
|
Beginning Month
|
|
Ending Month
|
|
Volumes (MMBtu)
|
|
Floor Price
|
|
Ceiling price
|
|
|
1/1/2011
|
|
|
|
4/30/2011
|
|
|
|
6,000
|
|
|
$
|
6.25
|
|
|
$
|
7.25
|
|
|
1/1/2011
|
|
|
|
8/31/2011
|
|
|
|
6,000
|
|
|
$
|
6.25
|
|
|
$
|
7.15
|
|
|
1/1/2011
|
|
|
|
12/31/2011
|
|
|
|
193,000
|
|
|
$
|
5.28
|
|
|
$
|
6.75
|
|
|
7/1/2011
|
|
|
|
12/31/2011
|
|
|
|
21,000
|
|
|
$
|
4.00
|
|
|
$
|
5.00
|
|
|
1/1/2012
|
|
|
|
12/31/2012
|
|
|
|
275,000
|
|
|
$
|
4.88
|
|
|
$
|
6.19
|
|
|
1/1/2013
|
|
|
|
12/31/2013
|
|
|
|
269,000
|
|
|
$
|
4.82
|
|
|
$
|
5.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Put Options
|
|
|
|
|
|
|
|
Average Monthly
|
|
|
|
|
Beginning Month
|
|
|
Ending Month
|
|
|
Volumes (MMBtu)
|
|
|
Strike Price
|
|
|
|
1/1/2011
|
|
|
|
12/31/2011
|
|
|
|
250,000
|
|
|
$
|
4.30
|
|
|
1/1/2012
|
|
|
|
12/31/2012
|
|
|
|
70,000
|
|
|
$
|
4.80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Collars
|
|
|
|
|
Average Monthly
|
|
Weighted Average
|
|
Weighted Average
|
Beginning Month
|
|
Ending Month
|
|
Volumes (Bbls)
|
|
Floor Price
|
|
Ceiling Price
|
|
|
1/1/2011
|
|
|
|
12/31/2011
|
|
|
|
1,200
|
|
|
$
|
75.00
|
|
|
$
|
94.00
|
|
|
1/1/2012
|
|
|
|
12/31/2012
|
|
|
|
900
|
|
|
$
|
73.33
|
|
|
$
|
94.97
|
|
|
1/1/2013
|
|
|
|
6/30/2013
|
|
|
|
300
|
|
|
$
|
80.00
|
|
|
$
|
99.60
|
|
|
1/1/2013
|
|
|
|
12/31/2013
|
|
|
|
600
|
|
|
$
|
70.00
|
|
|
$
|
104.70
|
|
In June 2010, the Predecessor entered into an interest rate swap
agreement in order to mitigate its exposure to interest rate
fluctuations. Under this swap agreement, the Predecessor
receives the current
1-month
LIBOR and pays a fixed rate of 1.00% on a notional amount of
$50.0 million. The effective date of the swap is from June
2010 to June 2012.
In 2009, the Predecessor entered into two interest rate swap
agreements in order to mitigate its exposure to interest rate
fluctuations. Under these swap agreements, the Predecessor pays
1.62% and receives the current
3-month
LIBOR rate per month on a notional amount of $6.7 million
and $1.7 million, respectively. The effective dates of the
swaps are from February 2009 to February 2011.
The interest rate swaps are not designated as hedges for
financial accounting purposes. All gains and losses, including
unrealized gains and losses related to the change in the
interest rate swaps fair value, have been recorded in Interest
expense, net in the combined statements of operations.
F-55
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
|
|
(c)
|
Balance
Sheet Presentation
|
The following table summarizes the gross fair value of
derivative instruments by the appropriate balance sheet
classification, even when the derivative instruments are subject
to netting arrangements and qualify for net presentation in the
Predecessors combined balance sheets at December 31,
2010 and 2009 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
Type
|
|
Balance Sheet Location(1)
|
|
2010
|
|
|
2009
|
|
|
Natural Gas Swaps
|
|
Short-term derivative instruments Current assets
|
|
$
|
1,661
|
|
|
$
|
1,311
|
|
Natural Gas Collars
|
|
Short-term derivative instruments Current assets
|
|
|
2,459
|
|
|
|
1,773
|
|
Natural Gas Swaps
|
|
Long-term derivative instruments Long-term assets
|
|
|
1,406
|
|
|
|
372
|
|
Natural Gas Collars
|
|
Long-term derivative instruments Long-term assets
|
|
|
1,627
|
|
|
|
491
|
|
Natural Gas Puts
|
|
Short-term derivative instruments Current liabilities
|
|
|
(23)
|
|
|
|
|
|
Natural Gas Collars
|
|
Short-term derivative instruments Current liabilities
|
|
|
(56)
|
|
|
|
|
|
Oil Collars
|
|
Short-term derivative instruments Current liabilities
|
|
|
(81)
|
|
|
|
(13)
|
|
Interest Rate Swaps
|
|
Short-term derivative instruments Current liabilities
|
|
|
(153)
|
|
|
|
|
|
Natural Gas Puts
|
|
Long-term derivative instruments Long-term
liabilities
|
|
|
(35)
|
|
|
|
|
|
Natural Gas Swaps
|
|
Long-term derivative instruments Long-term
liabilities
|
|
|
|
|
|
|
(104)
|
|
Natural Gas Collars
|
|
Long-term derivative instruments Long-term
liabilities
|
|
|
(174)
|
|
|
|
(49)
|
|
Oil Collars
|
|
Long-term derivative instruments Long-term
liabilities
|
|
|
(109)
|
|
|
|
(75)
|
|
Interest Rate Swaps
|
|
Long-term derivative instruments Long-term
liabilities
|
|
|
(250)
|
|
|
|
(107)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net derivative financial instruments
|
|
$
|
6,272
|
|
|
$
|
3,599
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The fair value of derivative instruments reported in the
Predecessors combined balance sheets are subject to
netting arrangements and qualify for net presentation. The
following table reports the net derivative fair values as
reported in the Predecessors combined balance sheets at
December 31, 2010 and 2009: |
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Combined balance sheet classification:
|
|
|
|
|
|
|
|
|
Current derivative contracts:
|
|
|
|
|
|
|
|
|
Assets
|
|
$
|
3,791
|
|
|
$
|
3,086
|
|
Liabilities
|
|
|
(109)
|
|
|
|
(13)
|
|
|
|
|
|
|
|
|
|
|
Net current
|
|
$
|
3,682
|
|
|
$
|
3,073
|
|
|
|
|
|
|
|
|
|
|
Noncurrent derivative contracts:
|
|
|
|
|
|
|
|
|
Assets
|
|
$
|
2,699
|
|
|
$
|
814
|
|
Liabilities
|
|
|
(109)
|
|
|
|
(288)
|
|
|
|
|
|
|
|
|
|
|
Net noncurrent
|
|
$
|
2,590
|
|
|
$
|
526
|
|
|
|
|
|
|
|
|
|
|
|
|
(d)
|
Gains
(Losses) on Derivatives
|
The Predecessor does not designate its derivative instruments as
hedging instruments for financial reporting purposes.
Accordingly, all gains and losses, including unrealized gains
and losses from changes in the derivative instruments fair
values, have been recorded in the combined statements of
operations. The
F-56
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
following table details the unrealized and realized gains and
losses related to derivative instruments for the years ending
December 31, 2010, 2009 and 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statements of
|
|
|
Years Ended December 31,
|
|
|
|
Operations Location
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Commodity derivative contracts(1)
|
|
|
Gain on derivatives
|
|
|
$
|
10,264
|
|
|
$
|
10,834
|
|
|
$
|
9,815
|
|
Interest rate swaps(2)
|
|
|
Interest expense
|
|
|
|
(576)
|
|
|
|
(165)
|
|
|
|
(482)
|
|
|
|
|
(1) |
|
Included in these amounts are net cash receipts of approximately
$7,294 and $17,574 for the years ended December 31, 2010
and 2009, respectively and net cash payments of $487 in 2008. |
|
(2) |
|
Included in the amounts are net cash payments of approximately
$281, $475 and $153 for the years ended December 31, 2010,
2009 and 2008, respectively. |
|
|
Note 6
|
Asset
Retirement Obligations
|
The Predecessor recognizes the fair value of its asset
retirement obligations related to the plugging, abandonment, and
remediation of oil and gas producing properties. The present
value of the estimated asset retirement costs has been
capitalized as part of the carrying amount of the related
long-lived assets. The present value of the estimated asset
retirement costs has been capitalized as part of the carrying
amount of the related long-lived assets, which approximated
$10.9 million and $3.8 million as of December 31,
2010 and 2009, respectively.
The liability has been accreted to its present value as of
December 31, 2010 and 2009. The Predecessor evaluated its
wells and determined a range of abandonment dates through 2061.
The following table represents a reconciliation of the
Predecessors asset retirement obligations for the years
ended December 31, 2010, 2009, and 2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Asset retirement obligations at beginning of year
|
|
$
|
3,806
|
|
|
$
|
3,342
|
|
|
$
|
1,940
|
|
Liabilities added from acquisitions or drilling
|
|
|
7,116
|
|
|
|
996
|
|
|
|
1,541
|
|
Liabilities removed upon sale of wells
|
|
|
(19)
|
|
|
|
(124)
|
|
|
|
(593)
|
|
Current year accretion expense
|
|
|
663
|
|
|
|
320
|
|
|
|
224
|
|
Revision of estimates
|
|
|
(674)
|
|
|
|
(728)
|
|
|
|
230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations at end of year
|
|
$
|
10,892
|
|
|
$
|
3,806
|
|
|
$
|
3,342
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On December 31, 2010, the Predecessor had debt outstanding
under two separate revolving credit facilities entered into by
BlueStone and Classic, respectively.
The
BlueStone Credit Facility
On July 8, 2009, BlueStone refinanced its existing
$100.0 million credit agreement with Bank of America, N.A.
by entering into a $150.0 million revolving credit facility
with various lenders. The $150.0 million credit facility
had an original maturity date of July 8, 2012, at which
time all principal and accrued interest amounts were due. On
June 25, 2010, BlueStone refinanced this credit facility
and entered into a $150.0 million revolving credit facility
with Wells Fargo Bank, NA (Wells Fargo) as
Administrative Agent. Amounts outstanding under the Wells Fargo
credit facility are payable on June 25, 2014 with mandatory
payments required if BlueStone makes any property dispositions.
At December 31, 2010 and 2009, $80.2 million and
$31.4 million, respectively, were outstanding under the
Wells Fargo credit facility.
F-57
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
Amounts outstanding under the Wells Fargo credit facility are
limited to a borrowing base which is determined twice per year.
In addition, BlueStone and the Administrative Agent can request
special borrowing base determinations, from time to time. If the
outstanding principal balance of the revolving credit facility
exceeds the borrowing base at any time, BlueStone must either
(a) reduce amounts outstanding under the revolving credit
facility in an amount to cure the deficiency, (b) pledge
additional oil and gas property as collateral sufficient to cure
the deficiency or (c) make monthly principal payments in
amounts that will cure the deficiency over the ensuing six-month
period. The borrowing base was $90.0 million at
December 31, 2010 and the borrowing base availability was
$9.5 million at December 31, 2010.
Adjusted Base Rate Advances and Adjusted LIBOR Rate Advances
under the revolving credit facility bear interest, payable
monthly, at an Adjusted Base Rate or Adjusted LIBOR Rate plus an
applicable margin of 1.75% and 2.75%, respectively. Amounts
outstanding under the facility for the years ended
December 31, 2010, 2009 and 2008 were at a weighted average
interest rate of approximately 3.45%, 4.88% and 5.31%,
respectively. The Wells Fargo revolving credit facility also
requires an annual commitment fee of 0.5%, payable quarterly.
Additionally, the revolving credit facility provides for the
issuance of letters of credit, limited to the total availability
under the facility. At December 31, 2010 and 2009,
BlueStone had $400,000 in letters of credit outstanding under
the facility.
BlueStones borrowings are secured by its assets and stock
and are subject to various financial and nonfinancial covenants.
Significant financial covenants include maintaining: (1) a
minimum current ratio, as defined, of 1.0 to 1.0, (2) a
minimum of EBITDA to interest expense, as defined, of 3.0 to
1.0, for the previous four quarters, and (3) a maximum of
total debt to EBITDA for the previous four quarters, as defined,
of 4.0 to 1.0. At December 31, 2010 and December 31,
2000, BlueStone was in compliance with its debt covenants.
The
Classic Credit Facility
The Classic Carve-Out properties are burdened by debt incurred
pursuant to a $150.0 million revolving credit facility
extended to Classic. Of the $105.0 million outstanding
under this facility at December 31, 2010,
$35.1 million pertained to the Classic Carve-Out
properties. The Classic credit facility has a termination date
of June 21, 2014. Borrowings under the Classic credit
facility bear interest, at the option of Classic, at either the
Prime Rate plus an applicable margin of 1.00% to 2.00% or LIBOR
plus and applicable margin of 2.00% or 3.00%. The margin rate is
determined by the percentage of the borrowing base outstanding.
The weighted average interest rate for the years ended
December 31, 2010, 2009 and 2008 was 3.1%, 3.6% and 4.9%,
respectively.
The borrowings under the Classic credit facility are secured by
the oil and gas properties of Classic and are subject to
semiannual borrowing base redeterminations. The borrowing base
at December 31, 2010 was $115.0 million, including
$38.5 million allocable to the Classic Carve-Out
properties. At December 31, 2010 Classic was in compliance
under existing debt covenants.
|
|
Note 8
|
Partners
Capital
|
The Predecessor generally allocates income and losses to the
partners based on each partners ownership percentage.
On February 6, 2006, BlueStone, Holdings and Holdings
members entered into a subscription and contribution agreement
whereby all equity contributions made by Holdings members
in exchange for equity units would be transferred directly to
BlueStone.
F-58
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
According to the Subscription and Contributions Agreement and
Amendments, members of Holdings have committed
$84.7 million in equity contributions as of
December 31, 2010. NGP VIII committed $75.7 million.
The remaining $9.0 million was committed by certain members
of BlueStones management. In 2010, BlueStone received an
equity contribution from members of Holdings of an additional
$40 million, including equity contributions of
$4.2 million from management. NGP VIII advanced certain
members of management $4.2 million to fund their equity
contributions in 2010. In exchange for these advances,
management issued notes payable which carry an interest rate of
2.72% and are payable May 28, 2015. The notes can be
declared immediately due and payable if the holder is no longer
employed by BlueStone or upon a merger, sale, or sale of
substantially all assets of BlueStone. At December 31,
2010, 100% of committed equity had been contributed.
On June 6, 2006, the partners of Classic entered into a
Limited Partnership Agreement (the Partnership
Agreement). According to the Partnership Agreement and
Amendments, partners of Classic have committed
$135.9 million in capital contributions as of
December 31, 2010, including $35.7 million allocable
to Classic Carve-Out. NGP VIII committed $123.0 million and
the remaining $12.9 million was committed by certain
members of Classics management. In 2010, Classic received
capital contributions of $19.7 million, net of equity
financing fees, from its partners, including $4.1 million
allocable to Classic Carve-Out. As of January 24, 2011,
100% of committed capital had been contributed.
|
|
Note 9
|
Incentive
Interests
|
At December 31, 2010, BlueStone and Classic each had
incentive units outstanding under their respective operating
agreements. The BlueStone and Classic operating agreements
provide for the issuance of up to 2,102,547 and
30,000 units, respectively. Holders of incentive units are
entitled to cash distributions following the sale, merger, or
other transaction involving the stock or assets of the companies
after the recovery of capital contributions plus a rate of
return, specified as payout levels in their respective operating
agreements.
Incentive units are subject to vesting or performance criteria,
as specified in the operating agreements. All incentive units
not vested are forfeited if an employee is no longer employed
and are forfeited automatically after February 6, 2014 for
BlueStone and October 26, 2012 for Classic.
The incentive units are accounted for as liability awards with
compensation expense based on period-end fair value. Because it
is not probable that the performance criterion has been met at
December 31, 2010, no compensation expense has been
recorded for any period in the combined Predecessor financial
statements.
|
|
Note 10
|
Related
Party Transactions
|
The majority partner of the Predecessor, NGP VIII, is an
affiliate of certain directors of the entities comprising the
Predecessor. For the periods ended December 31, 2010, 2009
and 2008, the Predecessor expensed advisory and directors
fees of approximately $151,000, $145,000 and $142,000,
respectively, to NGP VIII. At December 31, 2010 and 2009,
approximately $32,000 and $38,000, respectively, related to
these fees was recorded as a related-party payable.
|
|
Note 11
|
Commitments
and Contingencies
|
The Predecessor leases equipment and office space under
operating leases expiring on various dates through 2015. Rent
expense was approximately $273,000, $194,000, and $161,000 for
the years ended December 31, 2010, 2009, and 2008,
respectively. Minimum annual lease commitments at
December 31, 2010 for the calendar years following are
approximately $295,000 in 2011, $259,000 in 2012, $254,000 in
2013, $210,000 in 2014, and $17,000 thereafter. The Predecessor
moved their Laredo office in February 2011. Minimum lease
commitments under the new agreement are included in the amounts
above.
F-59
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
The Predecessor is involved in litigation in the normal course
of business. Management does not believe the outcome of these
matters will have a material adverse impact on the
Predecessors financial condition or results of operations.
|
|
(g)
|
Noncompete
Agreements
|
The Predecessor entered into noncompete agreements with certain
key employees which, in the event of the employees
termination for other than cause (as defined in the noncompete
agreements), provide for payments equal to the employees
regular monthly salary for a time period to be determined by the
Predecessor, but not to exceed 18 months.
|
|
Note 12
|
Defined
Contribution Plan
|
The companies comprising the Predecessor sponsor defined
contribution plans for the benefit of substantially all
employees who have attained 18 years of age. The plan
allows eligible employees to make tax-deferred contributions up
to 100% of their annual compensation, not to exceed annual
limits established by the Internal Revenue Service. The
Predecessor makes matching contributions of up to 6% of an
employees compensation and may make additional
discretionary contributions for eligible employees meeting
certain plan requirements. Employees vest ratably in the
employer discretionary contributions over three years. The
Predecessors contributions to the plan were approximately
$184,000, $170,000 and $126,000 in 2010, 2009 and 2008,
respectively.
|
|
Note 13
|
Subsequent
Events
|
Effective January 1, 2011, the Predecessor acquired BP
America Production Companys (BP) interests in
wells located in Duval, Jim Hogg, McMullen and Webb counties in
exchange for the Predecessors interest in the Nueces Field
of the Eagle Ford Shale and $20 million in cash, subject to
certain closing adjustments. The transaction closed on
May 31, 2011 and the Predecessor paid a total of
approximately $12.9 million in cash consideration at
closing, net of adjustments.
The Predecessor estimated that as of May 31, 2011, the
preliminary fair value of the net assets acquired from BP was
approximately $78.6 million. Taking into consideration the
cash consideration paid at closing of $12.9 million and the
carrying value of approximately $1.6 million for the assets
sold to BP in the transaction, which was primarily acreage, the
Predecessor expects to record a gain of approximately
$64 million during the
2nd
quarter of 2011. The purchase price allocation remains
preliminary and is subject to change until the purchase price
allocation is finalized.
On April 8, 2011, WHT acquired certain oil and natural gas
properties and related assets in East Texas from a third party
for approximately $315 million ($302.8 million after
customary adjustments) of which 40% will be contributed to the
Partnership.
F-60
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
|
|
Note 14
|
Supplemental
Oil and Gas Information (Unaudited)
|
Capitalized
Costs Relating to Oil and Natural Gas Producing
Activities
The following table illustrates the total amount of capitalized
costs relating to oil and natural gas producing activities and
the total amount of related accumulated depreciation, depletion
and amortization.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Evaluated oil and natural gas properties(1)
|
|
$
|
299,589
|
|
|
$
|
181,773
|
|
|
$
|
157,613
|
|
Unevaluated oil and natural gas properties
|
|
|
15,385
|
|
|
|
5,445
|
|
|
|
2,354
|
|
Accumulated depletion, depreciation and amortization(1)
|
|
|
(92,814
|
)
|
|
|
(60,978
|
)
|
|
|
(42,379
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
222,160
|
|
|
$
|
126,240
|
|
|
$
|
117,588
|
|
|
|
|
(1) |
|
Amounts do not include costs for our gas gathering systems and
related support equipment. |
Costs
Incurred in Oil and Natural Gas Property Acquisition,
Exploration and Development Activities
Costs incurred in property acquisition, exploration and
development activities were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Property acquisition costs, proved
|
|
$
|
104,542
|
|
|
$
|
17,455
|
|
|
$
|
15,199
|
|
Property acquisition costs, unproved
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration and extension well costs
|
|
|
6,287
|
|
|
|
6,808
|
|
|
|
16,726
|
|
Development costs(1)
|
|
|
6,842
|
|
|
|
12,226
|
|
|
|
28,652
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs
|
|
$
|
117,671
|
|
|
$
|
36,489
|
|
|
$
|
60,577
|
|
|
|
|
(1) |
|
Amounts do not include costs for our gas gathering systems and
related support equipment. |
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Natural Gas Reserves
The following Standardized Measure of Discounted Future Net Cash
Flows has been developed utilizing ASC 932, Extractive
Activities Oil and Gas, (ASC
932) procedures and based on oil and natural gas reserve
and production volumes estimated by the Predecessors
engineering staff. It can be used for some comparisons, but
should not be the only method used to evaluate the Predecessor
or its performance. Further, the information in the following
table may not represent realistic assessments of future cash
flows, nor should the Standardized Measure of Discounted Future
Net Cash Flows be viewed as representative of the current value
of the Predecessor.
The Partnership believes that the following factors should be
taken into account when reviewing the following information:
|
|
|
|
|
future costs and selling prices will probably differ from those
required to be used in these calculations;
|
|
|
|
due to future market conditions and governmental regulations,
actual rates of production in future years may vary
significantly from the rate of production assumed in the
calculations;
|
|
|
|
a 10% discount rate may not be reasonable as a measure of the
relative risk inherent in realizing future net oil and natural
gas revenues; and
|
|
|
|
future net revenues may be subject to different rates of income
taxation.
|
F-61
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
Under the Standardized Measure for the year ended
December 31, 2008, the future cash inflows were estimated
by applying year-end oil and natural gas prices to the estimated
future production of year-end proved reserves. Estimates of
future income taxes are computed using current statutory income
tax rates including consideration for estimated future statutory
depletion and tax credits. The resulting net cash flows are
reduced to present value amounts by applying a 10% discount
factor. Use of a 10% discount rate and year-end prices were
required. At December 31, 2010 and 2009, as specified by
the SEC, the prices for oil and natural gas used in this
calculation were the unweighted
12-month
average of the first day of the month prices, except for volumes
subject to fixed price contracts.
Oil
and Natural Gas Reserves
Users of this information should be aware that the process of
estimating quantities of proved and proved
developed oil and natural gas reserves is very complex,
requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each
reservoir. The data for a given reservoir may also change
substantially over time as a result of numerous factors
including, but not limited to, additional development activity,
evolving production history and continual reassessment of the
viability of production under varying economic conditions. As a
result, revisions to existing reserve estimates may occur from
time to time. Although every reasonable effort is made to ensure
reserve estimates reported represent the most accurate
assessments possible, the subjective decisions and variances in
available data for various reservoirs make these estimates
generally less precise than other estimates included in the
financial statement disclosures.
Proved reserves represent estimated quantities of natural gas,
crude oil and condensate that geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in
future years from known reservoirs under economic and operating
conditions in effect when the estimates were made. Proved
developed reserves are proved reserves expected to be recovered
through wells and equipment in place and under operating methods
used when the estimates were made.
The following table illustrates the Predecessors estimated
net proved reserves, including changes, and proved developed
reserves for the periods indicated, as estimated by Netherland,
Sewell & Associates, Inc. (NSAI) and Miller and Lents,
Ltd., each independent, third-party petroleum engineers. The oil
and natural gas liquids prices as of December 31, 2010 are
based on the respective
12-month
unweighted average of the first of the month prices of the WTI
Posting (Plains) spot price which equates to $75.96 per barrel.
The oil and natural gas liquids prices as of December 31,
2009 are based on the respective
12-month
unweighted average of the first of the month prices of the West
Texas Intermediate posted price which equates to $57.65 per
barrel. The oil and natural gas liquids price as of
December 31, 2008 is based on the year-end West Texas
Intermediate posted price of $41.00 per barrel. The oil and
natural gas liquids prices were adjusted by lease or field for
quality, transportation fees, and regional price differentials.
The natural gas prices as of December 31, 2010 and 2009 are
based on the respective
12-month
unweighted average of the first of the month prices of the Henry
Hub spot price which equates to $4.376 per MMbtu and $3.866 per
MMbtu, respectively. The natural gas price as of
December 31, 2008 is based on the year-end Henry Hub spot
market price of $5.71 per MMbtu. All prices are adjusted by
lease or field for energy content, transportation fees, and
regional price
F-62
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
differentials. All prices are held constant in accordance with
SEC guidelines. All proved reserves are located in the United
States.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquid
|
|
|
Equivalent
|
|
|
|
Oil (MBbls)
|
|
|
Gas (MMcf)
|
|
|
(MBbls)
|
|
|
(MMcfe)
|
|
|
Proved reserves, December 31, 2007
|
|
|
1,527
|
|
|
|
25,878
|
|
|
|
|
|
|
|
35,038
|
|
Extensions and discoveries
|
|
|
108
|
|
|
|
21,212
|
|
|
|
|
|
|
|
21,857
|
|
Purchase of minerals in place
|
|
|
46
|
|
|
|
6,199
|
|
|
|
|
|
|
|
6,480
|
|
Production
|
|
|
(55
|
)
|
|
|
(3,834
|
)
|
|
|
|
|
|
|
(4,165
|
)
|
Sale of minerals in place
|
|
|
(694
|
)
|
|
|
(1,211
|
)
|
|
|
|
|
|
|
(5,372
|
)
|
Revision of previous estimates
|
|
|
(98
|
)
|
|
|
9,955
|
|
|
|
|
|
|
|
9,365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, December 31, 2008
|
|
|
834
|
|
|
|
58,199
|
|
|
|
|
|
|
|
63,203
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions and discoveries
|
|
|
6
|
|
|
|
3,533
|
|
|
|
|
|
|
|
3,571
|
|
Purchase of minerals in place
|
|
|
32
|
|
|
|
8,001
|
|
|
|
|
|
|
|
8,195
|
|
Production
|
|
|
(94
|
)
|
|
|
(5,281
|
)
|
|
|
|
|
|
|
(5,847
|
)
|
Sale of minerals in place
|
|
|
(90
|
)
|
|
|
|
|
|
|
|
|
|
|
(538
|
)
|
Revision of previous estimates
|
|
|
51
|
|
|
|
(2,800
|
)
|
|
|
|
|
|
|
(2,495
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, December 31, 2009
|
|
|
739
|
|
|
|
61,652
|
|
|
|
|
|
|
|
66,089
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions and discoveries
|
|
|
60
|
|
|
|
7,602
|
|
|
|
211
|
|
|
|
9,225
|
|
Purchase of minerals in place
|
|
|
259
|
|
|
|
78,046
|
|
|
|
|
|
|
|
79,599
|
|
Production
|
|
|
(47
|
)
|
|
|
(7,314
|
)
|
|
|
(33
|
)
|
|
|
(7,792
|
)
|
Sale of minerals in place
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revision of previous estimates
|
|
|
5
|
|
|
|
11,190
|
|
|
|
271
|
|
|
|
12,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, December 31, 2010
|
|
|
1,016
|
|
|
|
151,176
|
|
|
|
449
|
|
|
|
159,971
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
Liquids
|
|
Equivalent
|
|
|
Oil (MBbls)
|
|
Gas (MMcf)
|
|
(MBbls)
|
|
(MMcfe)
|
|
December 31, 2010
|
|
|
904
|
|
|
|
123,529
|
|
|
|
206
|
|
|
|
130,195
|
|
December 31, 2009
|
|
|
687
|
|
|
|
47,809
|
|
|
|
|
|
|
|
51,934
|
|
December 31, 2008
|
|
|
769
|
|
|
|
43,291
|
|
|
|
|
|
|
|
47,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Undeveloped Reserves
|
|
|
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
Liquids
|
|
Equivalent
|
|
|
Oil (MBbls)
|
|
Gas (MMcf)
|
|
(MBbls)
|
|
(MMcfe)
|
|
December 31, 2010
|
|
|
112
|
|
|
|
27,647
|
|
|
|
243
|
|
|
|
29,775
|
|
December 31, 2009
|
|
|
52
|
|
|
|
13,843
|
|
|
|
|
|
|
|
14,155
|
|
December 31, 2008
|
|
|
65
|
|
|
|
14,908
|
|
|
|
|
|
|
|
15,298
|
|
Noteworthy amounts included in the categories of proved reserve
changes for the years 2010, 2009, and 2008 in the above tables
include: The Predecessor acquired 79.6 Bcfe in multiple
acquisitions, the largest being the Forest Oil properties of
47.0 Bcfe, during the year ended December 31, 2010.
8.2 Bcfe and 6.5 Bcfe were acquired in the years ended
December 31, 2009 and 2008, respectively, in multiple
acquisitions. See Note 3 Acquisitions and Divestitures for
additional information on acquisitions. The divestures in 2008
to multiple buyers totaled 5.4 MMcfe.
F-63
PREDECESSOR
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
The Predecessor did run an active drilling program in 2008 and
21.9 Bcfe was added to the reserve base. Reserves added
through extensions in 2009 and 2010 were not significant at
3.6 Bcfe and 9.2 Bcfe, respectively.
The SEC amended its definitions of oil and natural gas reserves
effective December 31, 2009. Previous periods were not
restated for the new rules. Key revisions include a change in
pricing used to prepare reserve estimates to a
12-month
unweighted average of the
first-day-of-the-month
prices, the inclusion of non-traditional resources in reserves,
definitional changes, allowing the application of reliable
technologies in determining proved reserves, and other new
disclosures (Revised SEC rules).
A variety of methodologies are used to determine our proved
reserve estimates. The principal methodologies employed are
reservoir simulation, decline curve analysis, volumetric,
material balance, advance production type curve matching,
petro-physics/log analysis and analogy. Some combination of
these methods is used to determine reserve estimates in
substantially all of our fields.
The Standardized Measure is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Future cash inflows
|
|
$
|
780,477
|
|
|
$
|
295,659
|
|
|
$
|
399,168
|
|
Future production costs
|
|
|
(291,486
|
)
|
|
|
(120,657
|
)
|
|
|
(136,118
|
)
|
Future development costs
|
|
|
(68,046
|
)
|
|
|
(31,180
|
)
|
|
|
(31,280
|
)
|
Future income tax expense(1)
|
|
|
(5,463
|
)
|
|
|
(2,070
|
)
|
|
|
(2,794
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows before 10% discount
|
|
$
|
415,482
|
|
|
$
|
141,752
|
|
|
$
|
228,976
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(231,667
|
)
|
|
|
(77,916
|
)
|
|
|
(125,090
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
183,815
|
|
|
$
|
63,836
|
|
|
$
|
103,886
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents future amounts owed associated with Texas margin tax. |
Changes
in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Natural Gas Reserves
The following is a summary of the changes in the Standardized
Measure for the Predecessors proved oil and natural gas
reserves during each of the years in the three year period ended
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Beginning of year
|
|
$
|
63,836
|
|
|
$
|
103,886
|
|
|
$
|
94,968
|
|
Sale of oil and natural gas produced, net of production costs
|
|
|
(21,222
|
)
|
|
|
(11,870
|
)
|
|
|
(38,657
|
)
|
Purchase of minerals in place
|
|
|
104,729
|
|
|
|
6,213
|
|
|
|
22,695
|
|
Sales of minerals in place
|
|
|
|
|
|
|
(612
|
)
|
|
|
(19,819
|
)
|
Extensions and discoveries
|
|
|
8,526
|
|
|
|
2,332
|
|
|
|
21,571
|
|
Changes in income taxes, net
|
|
|
(1,506
|
)
|
|
|
319
|
|
|
|
(225
|
)
|
Changes in prices and costs
|
|
|
14,198
|
|
|
|
(44,997
|
)
|
|
|
(10,679
|
)
|
Previously estimated development costs incurred
|
|
|
2,228
|
|
|
|
5,828
|
|
|
|
8,258
|
|
Net changes in future development costs
|
|
|
(4,947
|
)
|
|
|
1,253
|
|
|
|
(2,505
|
)
|
Revisions of previous quantities
|
|
|
12,192
|
|
|
|
(4,118
|
)
|
|
|
15,614
|
|
Accretion of discount
|
|
|
6,481
|
|
|
|
10,517
|
|
|
|
9,602
|
|
Changes in production rates and other
|
|
|
(700
|
)
|
|
|
(4,915
|
)
|
|
|
3,063
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
$
|
183,815
|
|
|
$
|
63,836
|
|
|
$
|
103,886
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-64
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Member
BlueStone Natural Resources, LLC:
We have audited the accompanying statements of revenues and
direct operating expenses of BlueStone Natural Resources,
LLCs acquisition of certain Forest Oil properties (the
Properties) for the years ended December 31, 2009 and 2008.
These financial statements are the responsibility of BlueStone
Natural Resources, LLCs management. Our responsibility is
to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted
auditing standards as established by the Auditing Standards
Board (United States) and in accordance with the auditing
standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
The accompanying statements of revenues and direct operating
expenses were prepared for the purpose of complying with the
rules and regulations of the Securities and Exchange Commission
as described in Note 1 to the statements, and is not
intended to be a complete presentation of the Properties
results of operations.
In our opinion, the statements of revenues and direct operating
expenses referred to above present fairly, in all material
respects, the results of BlueStone Natural Resources, LLCs
acquisition of certain Forest Oil properties operations for the
years ended December 31, 2009 and 2008, in conformity with
U.S. generally accepted accounting principles.
/s/ KPMG LLP
Oklahoma City, Oklahoma
June 10, 2011
F-65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
|
|
|
Year Ended December 31,
|
|
|
|
June 30, 2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(unaudited)
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Operating revenues
|
|
$
|
8,668
|
|
|
$
|
16,271
|
|
|
$
|
44,836
|
|
Direct operating expenses:
|
|
|
2,857
|
|
|
|
5,746
|
|
|
|
8,009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues in excess of direct operating expenses
|
|
$
|
5,811
|
|
|
$
|
10,525
|
|
|
$
|
36,827
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to statements of revenues and direct
operating expenses.
F-66
|
|
Note 1.
|
Basis of
Presentation
|
On June 30, 2010, BlueStone Natural Resources, LLC acquired
certain oil and gas properties from Forest Oil Corporation
(Forest Oil) for a net purchase price of
$65.9 million (referred to as the Forest Oil
Properties). The accompanying statements of revenues and
direct expenses are related to the Forest Oil Properties.
Historical financial statements prepared in accordance with
accounting principles generally accepted in the United States of
America have never been prepared for the Forest Oil Properties.
The accompanying statements of revenues and direct expenses
related to the Forest Oil Properties were prepared from the
historical accounting records of Forest Oil.
Certain indirect expenses, as further described in Note 4,
were not allocated to the Forest Oil Properties and have been
excluded from the accompanying statements. Any attempt to
allocate these expenses would require significant and judgmental
allocations, which would be arbitrary and may not be indicative
of the performance of the properties on a stand-alone basis.
These statements of revenues and direct expenses do not
represent a complete set of financial statements reflecting
financial position, results of operations, stakeholders
equity and cash flows of the Forest Oil Properties and are not
necessarily indicative of the results of operations for the
Forest Oil Properties going forward.
|
|
Note 2.
|
Significant
Accounting Policies
|
Use of
Estimates
Accounting principles generally accepted in the United States of
America require management to make estimates and assumptions
that affect the amounts reported in the statements of revenues
and direct expenses. Actual results could be different from
those estimates.
Revenue
Recognition
Forest Oil uses the sales method of accounting for oil and
natural gas revenues. Under the sales method, revenues are
recognized based on actual volumes of oil and natural gas sold
to purchasers. There were no significant imbalances with other
revenue interest owners during any of the periods presented in
these statements.
Direct
Operating Expenses
Direct expenses, which are recognized on an accrual basis,
relate to the direct expenses of operating the Forest Oil
Properties. The direct expenses include lease operating, ad
valorem tax and production tax expense. Lease operating expenses
include lifting costs, well repair expenses, surface repair
expenses, well workover costs and other field expenses. Lease
operating expenses also include expenses directly associated
with support personnel, support services, equipment and
facilities directly related to oil and natural gas production
activities.
The activities of the Forest Oil Properties are subject to
potential claims and litigation in the normal course of
operations. Forest Oil management does not believe that any
liability resulting from any pending or threatened litigation
will have a materially adverse effect on the operations or
financial results of the Forest Oil Properties.
F-67
FOREST
ACQUISITION FINANCIAL STATEMENTS
NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING
EXPENSES FOR
THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED)
(CONTINUED)
|
|
Note 4.
|
Excluded
Expenses
|
The Forest Oil Properties were part of a much larger enterprise
prior to the date of the sale by Forest Oil to BlueStone.
Indirect general and administrative expenses, interest, income
taxes, and other indirect expenses were not allocated to the
Forest Oil Properties and have been excluded from the
accompanying statements. In addition, any allocation of such
indirect expenses may not be indicative of costs which would
have been incurred by the Forest Oil Properties on a stand-alone
basis.
Also, depreciation, depletion, and amortization have been
excluded from the accompanying statements of revenues and direct
expenses as such amounts would not be indicative of the
depletion calculated on the Forest Oil Properties on a
stand-alone basis.
|
|
Note 5.
|
Supplemental
Information relating to oil and natural gas producing activities
(unaudited)
|
Estimated
Quantities of Proved Oil and Natural Gas Reserves
Users of this information should be aware that the process of
estimating quantities of proved and proved
developed oil and natural gas reserves is very complex,
requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each
reservoir. The data for a given reservoir may also change
substantially over time as a result of numerous factors
including, but not limited to, additional activity, evolving
production history and continual reassessment of the viability
of production under varying economic conditions. As a result,
revisions to existing reserve estimates may occur from time to
time. Although every reasonable effort is made to ensure reserve
estimates reported represent the most accurate assessments
possible, the subjective decisions and variances in available
data for various reservoirs make these estimates generally less
precise that other estimates included in the financial statement
disclosures.
Proved reserves represent estimated quantities of natural gas,
crude oil and condensate that geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in
future years from known reservoirs under economic and operating
conditions in effect when the estimates were made. Proved
developed reserves are proved reserves expected to be recovered
through wells and equipment in place and under operating methods
used when the estimates were made.
The following table illustrates the Forest Oil Properties
estimated net proved reserves, including changes and proved
developed reserves for the periods indicated. The oil price as
of December 31, 2009, is based on the twelve month
unweighted average of the first of the month prices of the West
Texas Intermediate posted price which equates to $61.18 per
barrel. Oil prices as of December 31, 2008, are based on
the respective year end West Texas Intermediate posted price of
$44.60 per barrel. The oil and natural gas liquids prices were
adjusted by lease for quality, transportation fees, and regional
price differentials.
The gas price as of December 31, 2009, is based on the
twelve month unweighted average of the first of the month prices
of the Henry Hub spot price which equates to $3.866 per MMbtu.
The gas price as of December 31, 2008, is based on the
respective year-end Henry Hub spot market price of $5.71 per
MMbtu. All prices are adjusted by lease of energy content,
transportation fees, and regional price differentials. All
F-68
FOREST
ACQUISITION FINANCIAL STATEMENTS
NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING
EXPENSES FOR
THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED)
(CONTINUED)
prices are held constant in accordance with SEC guidelines. All
proved reserves are located in Wells County, Texas.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves(1)
|
|
|
|
|
|
|
Equivalent
|
|
|
Oil (MBbls)
|
|
Gas (MMcf)
|
|
(MMcfe)
|
|
Proved reserves, December 31, 2007
|
|
|
176
|
|
|
|
61,050
|
|
|
|
62,103
|
|
Extensions and discoveries
|
|
|
1
|
|
|
|
613
|
|
|
|
621
|
|
Purchase of minerals in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(15
|
)
|
|
|
(5,152
|
)
|
|
|
(5,243
|
)
|
Sale of minerals in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Revision of previous estimates
|
|
|
(4
|
)
|
|
|
(761
|
)
|
|
|
(785
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, December 31, 2008
|
|
|
158
|
|
|
|
55,750
|
|
|
|
56,696
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Extensions and discoveries
|
|
|
|
|
|
|
532
|
|
|
|
533
|
|
Purchase of minerals in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(12
|
)
|
|
|
(4,347
|
)
|
|
|
(4,417
|
)
|
Sale of minerals in place
|
|
|
|
|
|
|
|
|
|
|
|
|
Revision of previous estimates
|
|
|
(11
|
)
|
|
|
(3,863
|
)
|
|
|
(3,926
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved reserves, December 31, 2009
|
|
|
135
|
|
|
|
48,072
|
|
|
|
48,886
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Proved reserves information is identical to proved developed
reserves information, as all proved reserves are also developed. |
The SEC amended its definitions of oil and natural gas reserves
effective December 31, 2009. Previous periods were not
restated for the new rules. Key revisions include a change in
pricing used to prepare reserve estimates to a twelve month
unweighted average of the
first-day-of-the-month
prices, the inclusion of non-traditional resources in reserves,
definitional changes, and allowing the application of reliable
technologies in determining proved reserves, and other new
disclosures.
The reserves described above have been estimated by management,
using deterministic methods. For wells classified as proved
developed producing where sufficient production history existed,
reserves were based on individual well performance evaluation
and production decline curve extrapolation techniques. For
undeveloped locations and wells that lack sufficient production
history, reserves were based on analogy to producing wells
within the same area exhibiting similar geologic and reservoir
characteristics, combined with volumetric methods. The
volumetric estimates were based on geologic maps and rock and
fluid properties derived from well logs, core data, pressure
measurements, and fluid samples. Well spacing was determined
from drainage patterns derived from a combination of
performance-based recoveries and volumetric estimates for each
area or field. Proved undeveloped locations were limited to
areas of uniformly high quality reservoir properties, between
existing commercial producers.
Standardized
Measure of Discounted Future Net Cash Flows Relating to Oil and
Gas Reserves
The following Standardized Measure of Discounted Future Net Cash
Flow information has been developed utilizing ASC 932,
Extractive Activities Oil and Gas, (ASC932)
procedures and based on oil and natural gas reserve and
production volumes estimated by the Companys engineering
staff. It can be used for some comparisons, but should not be
the only method used to evaluate the Forest Oil Properties or
their
F-69
FOREST
ACQUISITION FINANCIAL STATEMENTS
NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING
EXPENSES FOR
THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED)
(CONTINUED)
performance. Further, the information in the following table may
not represent realistic assessments of future cash flows, nor
should the Standardized Measure of Discounted future Net Cash
Flow be viewed as representative of the current value of the
Forest Oil Properties.
Standardized
Measure of Discounted Future Net Cash Flows Relating to Oil and
Gas Reserves
The Partnership believes that the following factors should be
taken into account when reviewing the following information:
|
|
|
|
|
future costs and selling prices will probably differ from those
required to be used in these calculations;
|
|
|
|
due to future market conditions and governmental regulations,
actual rates of production in future years may vary
significantly from the rate of production assumed in the
calculations;
|
|
|
|
a 10% discount rate may not be reasonable as a measure of the
relative risk inherent in realizing future net oil and natural
revenues; and
|
|
|
|
the effects of federal income taxes have been excluded
|
Under the Standardized Measure, for the year ended
December 31, 2009 and 2008 the future cash inflows were
estimated by applying unweighted twelve month average of the
first day of the month cash price quotes to the estimated future
production of period end proved reserves. The resulting net cash
flows are reduced to present value amounts by applying a 10%
discount factor. Use of a 10% discount rate and the unweighted
twelve month average prices were required.
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Future cash inflows
|
|
$
|
194,467
|
|
|
$
|
327,588
|
|
Future production costs
|
|
|
(86,297
|
)
|
|
|
(122,126
|
)
|
Future development costs
|
|
|
|
|
|
|
|
|
Future income tax expense(1)
|
|
|
(1,361
|
)
|
|
|
(2,293
|
)
|
|
|
|
|
|
|
|
|
|
Future net cash flows before 10% discount
|
|
$
|
106,809
|
|
|
$
|
203,169
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(48,663
|
)
|
|
|
(98,675
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
58,146
|
|
|
$
|
104,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Represents future amounts owed associated with Texas margin tax. |
F-70
FOREST
ACQUISITION FINANCIAL STATEMENTS
NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING
EXPENSES FOR
THE YEARS ENDED DECEMBER 31, 2009 AND 2008 AND
SIX MONTHS ENDED JUNE 30, 2010 (UNAUDITED)
(CONTINUED)
Changes
in Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Natural Gas Reserves
The following tabulation is a summary of changes between the
total standardization measure of discounted future net cash
flows at the beginning and end of each year:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Beginning of year
|
|
$
|
104,494
|
|
|
$
|
143,713
|
|
Sale of oil and natural gas produced, net of production costs
|
|
|
(10,525
|
)
|
|
|
(36,827
|
)
|
Purchase of minerals in place
|
|
|
|
|
|
|
|
|
Sales of minerals in place
|
|
|
|
|
|
|
|
|
Extensions and discoveries
|
|
|
1,314
|
|
|
|
1,679
|
|
Changes in income taxes, net
|
|
|
410
|
|
|
|
331
|
|
Changes in prices and costs
|
|
|
(40,554
|
)
|
|
|
(16,934
|
)
|
Previously estimated development costs incurred
|
|
|
|
|
|
|
|
|
Net changes in future development costs
|
|
|
|
|
|
|
|
|
Revisions of previous quantities
|
|
|
(7,312
|
)
|
|
|
(1,834
|
)
|
Accretion of discount
|
|
|
10,560
|
|
|
|
14,515
|
|
Changes in production rates and other
|
|
|
(241
|
)
|
|
|
(149
|
)
|
End of year
|
|
$
|
58,146
|
|
|
$
|
104,494
|
|
F-71
REPORT OF
INDEPENDENT AUDITORS
The Members
BlueStone Natural Resources, LLC
We have audited the accompanying statements of revenues and
direct operating expenses of the oil and gas properties acquired
by BlueStone Natural Resources, LLC from BP America Production
Company (the BP Properties), as described in Note 1, for
each of the three years in the period ended December 31,
2010. These financial statements are the responsibility of
BlueStone Natural Resources, LLCs and BP America
Production Companys management. Our responsibility is to
express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States. Those standards require
that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the basis
of accounting used and significant estimates made by management,
as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable
basis for our opinion.
The accompanying financial statements were prepared for the
purpose of complying with the rules and regulations of the
Securities and Exchange Commission for inclusion in Memorial
Production Partners LPs
Form S-1,
and are not intended to be a complete financial presentation of
the BP Properties revenues and expenses.
In our opinion, the financial statements referred to above
presents fairly, in all material respects, the revenues and
direct operating expenses, as described in Note 1, of the
BP Properties for each of the three years in the period ended
December 31, 2010, in conformity with U.S. generally
accepted accounting principles.
Houston, Texas
June 17, 2011
F-72
BLUESTONE
NATURAL RESOURCES, LLCS ACQUISITION OF
CERTAIN BP AMERICA PRODUCTION COMPANY PROPERTIES
STATEMENTS
OF REVENUES AND DIRECT OPERATING EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
|
March 31,
|
|
|
For Years Ended December 31,
|
|
|
|
2011
|
|
|
2010
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
|
Operating revenues
|
|
$
|
3,732
|
|
|
$
|
6,482
|
|
|
$
|
18,896
|
|
|
$
|
18,972
|
|
|
$
|
45,538
|
|
Direct operating expenses
|
|
|
1,572
|
|
|
|
2,280
|
|
|
|
7,003
|
|
|
|
6,535
|
|
|
|
9,016
|
|
Revenues in excess of direct operating expenses
|
|
$
|
2,160
|
|
|
$
|
4,202
|
|
|
$
|
11,893
|
|
|
$
|
12,437
|
|
|
$
|
36,522
|
|
See accompanying notes to the statements of revenues and direct
operating expenses.
F-73
|
|
Note 1:
|
Basis of
Presentation
|
On May 31, 2011, BlueStone Natural Resources, LLC
(BlueStone) acquired certain oil and gas properties
from BP America Production Company (BP) through an
exchange of BlueStones Eagle Ford assets located in Texas
plus a cash payment of $20.0 million in exchange for
BPs South Texas assets (BP Properties). The
accompanying statements of revenues and direct operating
expenses are related to the BP Properties.
Historical financial statements prepared in accordance with
accounting principles generally accepted in the United States of
America have never been prepared for the BP Properties. The
accompanying statements of revenues and direct operating
expenses related to the BP Properties were prepared from the
historical accounting records of BP.
Certain indirect expenses, as further described in Note 4,
were not allocated to the BP Properties and have been excluded
from the accompanying statements. Any attempt to allocate these
expenses would require significant and judgmental allocations,
which would be arbitrary and may not be indicative of the
performance of the properties on a stand-alone basis.
These statements of revenues and direct operating expenses do
not represent a complete set of financial statements reflecting
financial position, results of operations, stakeholders
equity and cash flows of the BP Properties and are not
necessarily indicative of the results of operations for the BP
Properties going forward.
As of May 31, 2011, there are no preferential rights
outstanding on the properties acquired by BlueStone.
|
|
Note 2:
|
Significant
Account Policies
|
Use of
Estimates
Accounting principles generally accepted in the United States of
America require management to make estimates and assumptions
that affect the amounts reported in the statements of revenues
and direct operating expenses. Actual results could be different
from those estimates.
Revenue
Recognition
BP uses the sales method of accounting for oil and natural gas
revenues. Under the sales method, revenues are recognized based
on actual volumes of oil and natural gas sold to purchasers.
There were no significant imbalances with other revenue interest
owners during any of the periods presented in these statements.
Direct
Operating Expenses
Direct operating expenses, which are recognized on an accrual
basis, relate to the direct expenses of operating the BP
Properties. The direct expenses include lease operating, ad
valorem tax and production tax expense. Lease operating expenses
include lifting costs, well repair expenses, surface repair
expenses, well workover costs and other field expenses. Lease
operating expenses also include expenses directly associated
with support personnel, support services, equipment and
facilities directly related to oil and natural gas production
activities of the BP Properties.
F-74
BLUESTONE
NATURAL RESOURCES, LLCS ACQUISITION OF
CERTAIN BP AMERICA PRODUCTION COMPANY PROPERTIES
NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING
EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
AND FOR THE THREE MONTHS ENDED MARCH 31, 2011 AND 2010
(UNAUDITED) (Continued)
|
|
Note 3:
|
Commitment
and Contingencies
|
The activities of the BP Properties are subject to potential
claims and litigation in the normal course of operations.
Pursuant to the terms of the asset exchange agreement between BP
and BlueStone, any claims, litigation or disputes pending as of
the effective date (January 1, 2011) or any matters
arising in connection with ownership of the properties prior to
the effective date are retained by BP.
|
|
Note 4:
|
Excluded
Expenses
|
The BP Properties were part of a much larger enterprise prior to
the date of the sale by BP to BlueStone. Indirect general and
administrative expenses, interest, income taxes, and other
indirect expenses were not allocated to the BP Properties and
have been excluded from the accompanying statements. In
addition, any allocation of such indirect expenses may not be
indicative of costs which would have been incurred by the BP
Properties on a stand-alone basis.
Also, depreciation, depletion, and amortization have been
excluded from the accompanying statements of revenues and direct
operating expenses as such amounts would not be indicative of
the depletion calculated on the BP Properties on a stand-alone
basis.
|
|
Note 5:
|
Sales to
Affiliates
|
Sales prices are based on current market prices at the time of
sale. Total sales to affiliates were $12.5 million,
$10.8 million, and $25.4 million for the years ended
December 31, 2010, 2009, and 2008, respectively. Total
sales to affiliates were $2.4 million and $4.2 million
for the unaudited three months ended March 31, 2011 and
2010, respectively.
Note 6: Capital
Expenditures (unaudited)
Capital expenditures for the BP properties were
$0.2 million, $0.9 million, and $5.4 million for
the years ended December 31, 2010, 2009, and 2008,
respectively. Capital expenditures for each of the three months
periods ended March 31, 2011 and 2010 were less than
$0.1 million.
|
|
Note 7:
|
Subsequent
Events
|
Subsequent events have been evaluated for recognition and
disclosure through June 17, 2011. As of this date, no
subsequent events have occurred.
F-75
Supplemental
Oil and Gas Information (unaudited)
Historical data provided by BP and supplemented by qualified
petroleum engineers on the staff of BlueStone was provided to
Netherland, Sewell & Associates, Inc. (NSAI),
independent, third-party petroleum engineers, to perform an
independent evaluation of proved reserves for the year ending
December 31, 2010. Reserves for the years ended
December 31, 2009, 2008, and 2007 have been estimated by
BlueStone petroleum engineers using the December 31, 2010
reserve study and adjusting it for actual production and changes
in prices for the intervening periods.
All information set forth herein relating to proved reserves as
of December 31, 2010, including estimated future net cash
flows and present values, from that date, is taken or derived
from reports and information furnished by BP. These estimates
were based upon review of historical production data and other
geological, economic, ownership and engineering data provided
and related to the reserves. No reports on our reserves have
been filed with any federal agency. In accordance with the
SECs guidelines, our estimates of proved reserves and the
future net revenues from which present values are derived
beginning in 2009, are based on an unweighted
12-month
average of the
first-day-of-the-month
price for the period, held constant throughout the life of the
properties. The 2007 and 2008 prices are based on the prices
being realized as of the last day of the year in accordance with
the then SEC guidelines. Operating costs, development costs and
certain production-related taxes were deducted in arriving at
estimated future net revenues.
The following unaudited table sets forth proved natural gas and
crude oil reserves, all within the United States, at
December 31, 2010, 2009 and 2008, together with the changes
therein.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Crude
|
|
|
|
|
|
|
(MMcf)
|
|
|
Oil (MBbls)
|
|
|
Total (MMcfe)
|
|
|
Quantities of proved reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007
|
|
|
63,953
|
|
|
|
89
|
|
|
|
64,487
|
|
Revisions(1)
|
|
|
(709
|
)
|
|
|
(1
|
)
|
|
|
(715
|
)
|
Extensions
|
|
|
25
|
|
|
|
|
|
|
|
25
|
|
Production
|
|
|
(5,890
|
)
|
|
|
(8
|
)
|
|
|
(5,938
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2008
|
|
|
57,379
|
|
|
|
80
|
|
|
|
57,859
|
|
Revisions(1)
|
|
|
(3,124
|
)
|
|
|
(4
|
)
|
|
|
(3,148
|
)
|
Extensions
|
|
|
533
|
|
|
|
|
|
|
|
533
|
|
Production
|
|
|
(5,405
|
)
|
|
|
(7
|
)
|
|
|
(5,447
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2009
|
|
|
49,383
|
|
|
|
69
|
|
|
|
49,797
|
|
Revisions(1)
|
|
|
2,089
|
|
|
|
5
|
|
|
|
2,119
|
|
Production
|
|
|
(4,787
|
)
|
|
|
(9
|
)
|
|
|
(4,841
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2010
|
|
|
46,685
|
|
|
|
65
|
|
|
|
47,075
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Revisions include only the impact of changes in product prices. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
Crude
|
|
|
|
|
(MMcf)
|
|
Oil (MBbls)
|
|
Total (MMcfe)
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
63,953
|
|
|
|
89
|
|
|
|
64,487
|
|
December 31, 2008
|
|
|
57,379
|
|
|
|
80
|
|
|
|
57,859
|
|
December 31, 2009
|
|
|
49,383
|
|
|
|
69
|
|
|
|
49,797
|
|
December 31, 2010
|
|
|
46,685
|
|
|
|
65
|
|
|
|
47,075
|
|
F-76
Standardized measure of discounted future net cash flows
relating to proved reserves (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Future cash inflows
|
|
$
|
201,777
|
|
|
$
|
187,622
|
|
|
$
|
317,502
|
|
Future production and development costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(85,159
|
)
|
|
|
(81,653
|
)
|
|
|
(115,267
|
)
|
Development
|
|
|
|
|
|
|
|
|
|
|
|
|
Future income taxes
|
|
|
(1,412
|
)
|
|
|
(1,313
|
)
|
|
|
(2,223
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
115,206
|
|
|
|
104,656
|
|
|
|
200,012
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(57,867
|
)
|
|
|
(51,252
|
)
|
|
|
(103,334
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
57,339
|
|
|
$
|
53,404
|
|
|
$
|
96,678
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows are computed by applying a
12-month
average commodity price adjusted for location and quality
differentials for 2010 and 2009, to year-end quantities of
proved reserves, except in those instances where fixed and
determinable price changes are provided by contractual
arrangements at year-end. The 2008 prices were computed on the
year end prices in accordance with the, then current, SEC
guidance. The discounted future cash flow estimates do not
include the effects of derivative instruments. Average price per
commodity follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum Product
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Natural Gas per Mcf
|
|
$
|
4.22
|
|
|
$
|
3.72
|
|
|
$
|
5.48
|
|
Crude Oil per Bbl
|
|
$
|
73.17
|
|
|
$
|
56.28
|
|
|
$
|
40.89
|
|
The following reconciles the change in the standardized measure
of discounted future net cash flows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Standardized measure of discounted future net cash flow,
beginning of year
|
|
$
|
53,404
|
|
|
$
|
96,678
|
|
|
$
|
134,649
|
|
Changes from:
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales of natural gas, crude oil and natural gas liquids
produced, net of production costs
|
|
|
(12,583
|
)
|
|
|
(11,439
|
)
|
|
|
(37,994
|
)
|
Extensions
|
|
|
|
|
|
|
1,314
|
|
|
|
80
|
|
Net changes in prices and production costs
|
|
|
10,285
|
|
|
|
(40,132
|
)
|
|
|
(13,821
|
)
|
Revisions of previous quantity estimates
|
|
|
2,610
|
|
|
|
(5,313
|
)
|
|
|
(1,508
|
)
|
Net change in taxes
|
|
|
(35
|
)
|
|
|
379
|
|
|
|
320
|
|
Accretion of discount
|
|
|
5,402
|
|
|
|
9,767
|
|
|
|
13,596
|
|
Change in timing and other
|
|
|
(1,744
|
)
|
|
|
2,150
|
|
|
|
1,356
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate change in standardized measure of discounted future
net cash flows
|
|
|
3,935
|
|
|
|
(43,274
|
)
|
|
|
(37,971
|
)
|
Standardized measure of discounted future net cash flow, end of
year
|
|
$
|
57,339
|
|
|
$
|
53,404
|
|
|
$
|
96,678
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-77
APPENDIX B
Glossary
of Terms
The following includes a description of the meanings of some of
the oil and natural gas industry terms used in this prospectus.
Analogous Reservoir: Analogous
reservoirs, as used in resource assessments, have similar rock
and fluid properties, reservoir conditions (depth, temperature,
and pressure) and drive mechanisms, but are typically at a more
advanced stage of development than the reservoir of interest and
thus may provide concepts to assist in the interpretation of
more limited data and estimation of recovery. When used to
support proved reserves, analogous reservoir refers to a
reservoir that shares all of the following characteristics with
the reservoir of interest: (i) the same geological
formation (but not necessarily in pressure communication with
the reservoir of interest); (ii) the same environment of
deposition; (iii) similar geologic structure; and
(iv) the same drive mechanism.
API Gravity: A system of classifying
oil based on its specific gravity, whereby the greater the
gravity, the lighter the oil.
Basin: A large depression on the
earths surface in which sediments accumulate.
Bbl: One stock tank barrel, or 42
U.S. gallons liquid volume, used in reference to oil or
other liquid hydrocarbons.
Bbl/d: One Bbl per day.
Bcf: One billion cubic feet of natural
gas.
Bcfe: One billion cubic feet of natural
gas equivalent.
Boe: One barrel of oil equivalent,
calculated by converting natural gas to oil equivalent barrels
at a ratio of six Mcf of natural gas to one Bbl of oil.
Boe/d: One Boe per day.
Btu: One British thermal unit, the
quantity of heat required to raise the temperature of a
one-pound mass of water by one degree Fahrenheit.
Deterministic Estimate: The method of
estimating reserves or resources is called deterministic when a
single value for each parameter (from the geoscience,
engineering or economic data) in the reserves calculation is
used in the reserves estimation procedure.
Development Project: A development
project is the means by which petroleum resources are brought to
the status of economically producible. As examples, the
development of a single reservoir or field, an incremental
development in a producing field or the integrated development
of a group of several fields and associated facilities with a
common ownership may constitute a development project.
Developed Acreage: The number of acres
which are allocated or assignable to producing wells or wells
capable of production.
Development Well: A well drilled within
the proved area of an oil or natural gas reservoir to the depth
of a stratigraphic horizon known to be productive.
Differential: An adjustment to the
price of oil or natural gas from an established spot market
price to reflect differences in the quality
and/or
location of oil or natural gas.
Dry Hole Or Dry Well: A well found to
be incapable of producing hydrocarbons in sufficient quantities
such that proceeds from the sale of such production would exceed
production expenses and taxes.
Economically Producible: The term
economically producible, as it relates to a resource, means a
resource which generates revenue that exceeds, or is reasonably
expected to exceed, the costs of the operation.
B-1
The value of the products that generate revenue shall be
determined at the terminal point of oil and natural gas
producing activities.
Estimated Ultimate Recovery: Estimated
ultimate recovery is the sum of reserves remaining as of a given
date and cumulative production as of that date.
Exploitation: A development or other
project which may target proven or unproven reserves (such as
probable or possible reserves), but which generally has a lower
risk than that associated with exploration projects.
Exploratory Well: A well drilled to
find and produce oil and natural gas reserves not classified as
proved, to find a new reservoir in a field previously found to
be productive of oil or natural gas in another reservoir or to
extend a known reservoir.
Field: An area consisting of a single
reservoir or multiple reservoirs, all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition. The field name refers to the surface
area, although it may refer to both the surface and the
underground productive formations.
Gross Acres or Gross
Wells: The total acres or wells, as the case
may be, in which we have working interest.
MBbl: One thousand Bbls.
MBbls/d: One thousand Bbls per day.
MBoe: One thousand Boe.
MBoe/d: One thousand Boe per day.
MBtu: One thousand Btu.
MBtu/d: One thousand Btu per day.
Mcf: One thousand cubic feet of natural
gas.
Mcf/d: One Mcf per day.
MMBtu: One million British thermal
units.
MMcf: One million cubic feet of natural
gas.
MMcfe: One million cubic feet of
natural gas equivalent.
Net Acres or Net
Wells: Gross acres or wells, as the case may
be, multiplied by our working interest ownership percentage
working interest.
Net Production: Production that is
owned by us less royalties and production due others.
Net Revenue Interest: A working
interest owners gross working interest in production less
the royalty, overriding royalty, production payment and net
profits interests.
NGLs: The combination of ethane,
propane, butane and natural gasolines that when removed from
natural gas become liquid under various levels of higher
pressure and lower temperature.
NYMEX: New York Mercantile Exchange.
Oil: Oil and condensate and natural gas
liquids.
Operator: The individual or company
responsible for the exploration
and/or
production of an oil or natural gas well or lease.
Play: A geographic area with
hydrocarbon potential.
Probabilistic Estimate: The method of
estimation of reserves or resources is called probabilistic when
the full range of values that could reasonably occur for each
unknown parameter (from the geoscience and
B-2
engineering data) is used to generate a full range of possible
outcomes and their associated probabilities of occurrences.
Productive Well: A well that produces
commercial quantities of hydrocarbons, exclusive of its capacity
to produce at a reasonable rate of return.
Proved Developed Reserves: Proved
reserves that can be expected to be recovered from existing
wells with existing equipment and operating methods.
Proved Reserve Additions: The sum of
additions to proved reserves from extensions, discoveries,
improved recovery, acquisitions and revisions of previous
estimates.
Proved Reserves: Those quantities of
oil and natural gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to
be economically producible, from a given date forward, from
known reservoirs, and under existing economic conditions,
operating methods, and government regulations, prior to the time
at which contracts providing the right to operate expire, unless
evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are
used for the estimation. The project to extract the hydrocarbons
must have commenced, or the operator must be reasonably certain
that it will commence the project, within a reasonable time. The
area of the reservoir considered as proved includes (i) the
area identified by drilling and limited by fluid contacts, if
any, and (ii) adjacent undrilled portions of the reservoir
that can, with reasonable certainty, be judged to be continuous
with it and to contain economically producible oil or natural
gas on the basis of available geoscience and engineering data.
In the absence of data on fluid contacts, proved quantities in a
reservoir are limited by the lowest known hydrocarbons, LKH, as
seen in a well penetration unless geoscience, engineering or
performance data and reliable technology establishes a lower
contact with reasonable certainty. Where direct observation from
well penetrations has defined a highest known oil, HKO,
elevation and the potential exists for an associated natural gas
cap, proved oil reserves may be assigned in the structurally
higher portions of the reservoir only if geoscience,
engineering, or performance data and reliable technology
establish the higher contact with reasonable certainty. Reserves
which can be produced economically through application of
improved recovery techniques (including, but not limited to,
fluid injection) are included in the proved classification when
(i) successful testing by a pilot project in an area of the
reservoir with properties no more favorable than in the
reservoir as a whole, the operation of an installed program in
the reservoir or an analogous reservoir or other evidence using
reliable technology establishes the reasonable certainty of the
engineering analysis on which the project or program was based;
and (ii) the project has been approved for development by
all necessary parties and entities, including governmental
entities. Existing economic conditions include prices and costs
at which economic producibility from a reservoir is to be
determined. The price shall be the average price during the
twelve-month period prior to the ending date of the period
covered by the report, determined as an unweighted arithmetic
average of the
first-day-of-the-month
price for each month within such period, unless prices are
defined by contractual arrangements, excluding escalations based
upon future conditions.
Proved Undeveloped Reserves: Proved oil
and natural gas reserves that are expected to be recovered from
new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Reserves on undrilled acreage shall be limited to those drilling
units offsetting productive units that are reasonably certain of
production when drilled. Proved reserves for other undrilled
units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the
existing productive formation. Under no circumstances should
estimates for proved undeveloped reserves be attributable to any
acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the
area and in the same reservoir.
Realized Price: The cash market price
less all expected quality, transportation and demand adjustments.
Recompletion: The completion for
production of an existing wellbore in another formation from
that which the well has been previously completed.
Reliable Technology: Reliable
technology is a grouping of one or more technologies (including
computational methods) that has been field tested and has been
demonstrated to provide reasonably certain results with
consistency and repeatability in the formation being evaluated
or in an analogous formation.
B-3
Reserves: Reserves are estimated
remaining quantities of oil and natural gas and related
substances anticipated to be economically producible, as of a
given date, by application of development projects to known
accumulations. In addition, there must exist, or there must be a
reasonable expectation that there will exist, the legal right to
produce or a revenue interest in the production, installed means
of delivering oil and natural gas or related substances to
market and all permits and financing required to implement the
project. Reserves should not be assigned to adjacent reservoirs
isolated by major, potentially sealing, faults until those
reservoirs are penetrated and evaluated as economically
producible. Reserves should not be assigned to areas that are
clearly separated from a known accumulation by a non-productive
reservoir (i.e., absence of reservoir, structurally low
reservoir or negative test results). Such areas may contain
prospective resources (i.e., potentially recoverable resources
from undiscovered accumulations).
Reserve Life: A measure of the
productive life of an oil and natural gas property or a group of
properties, expressed in years. Reserve life is calculated by
dividing proved reserve volumes at year-end by production
volumes. In our calculation of reserve life, production volumes
are based on annualized fourth quarter production and are
adjusted, if necessary, to reflect property acquisitions and
dispositions.
Reservoir: A porous and permeable
underground formation containing a natural accumulation of
producible oil
and/or
natural gas that is confined by impermeable rock or water
barriers and is individual and separate from other reserves.
Resources: Resources are quantities of
oil and natural gas estimated to exist in naturally occurring
accumulations. A portion of the resources may be estimated to be
recoverable and another portion may be considered unrecoverable.
Resources include both discovered and undiscovered accumulations.
Spacing: The distance between wells
producing from the same reservoir. Spacing is often expressed in
terms of acres (e.g.,
40-acre
spacing) and is often established by regulatory agencies.
Spot Price: The cash market price
without reduction for expected quality, transportation and
demand adjustments.
Standardized Measure: The present value
of estimated future net revenue to be generated from the
production of proved reserves, determined in accordance with the
rules and regulations of the SEC (using prices and costs in
effect as of the date of estimation), less future development,
production and income tax expenses, and discounted at 10% per
annum to reflect the timing of future net revenue. Because we
are a limited partnership, we are generally not subject to
federal or state income taxes and thus make no provision for
federal or state income taxes in the calculation of our
standardized measure. Standardized measure does not give effect
to derivative transactions.
Undeveloped Acreage: Lease acreage on
which wells have not been drilled or completed to a point that
would permit the production of commercial quantities of oil and
natural gas regardless of whether such acreage contains proved
reserves.
Wellbore: The hole drilled by the bit
that is equipped for oil or natural gas production on a
completed well. Also called well or borehole.
Working Interest: An interest in an oil
and natural gas lease that gives the owner of the interest the
right to drill for and produce oil and natural gas on the leased
acreage and requires the owner to pay a share of the costs of
drilling and production operations.
Workover: Operations on a producing
well to restore or increase production.
WTI: West Texas Intermediate.
The terms analogous reservoir, development
project, development well, economically
producible, estimated ultimate recovery,
exploratory well, probabilistic
estimate, proved developed reserves,
proved reserves, proved undeveloped
reserves, reliable technology,
reserves, and resources are defined by
the SEC.
B-4
APPENDIX C
Netherland,
Sewell & Associates, Inc. Summary of December 31,
2010 Reserves
June 17,
2011
Mr. Doug
Redmond
BlueStone Natural Resources
2100 South Utica, Suite 200
Tulsa, Oklahoma 74114
Dear Mr. Redmond:
In accordance with your request, we have estimated the proved
reserves and future revenue, as of December 31, 2010, to
the BlueStone Natural Resources (BlueStone) interest in certain
oil and gas properties located in Texas. As requested, the
BlueStone working and net revenue interests shown in this report
include the interests being acquired from BP America Production
Company. It is our understanding that this acquisition had an
effective date of January 1, 2011, and closed on
May 31, 2011. We completed our evaluation on May 23,
2011. It is our understanding that the proved reserves estimated
in this report constitute approximately 96 percent of all
proved reserves owned by BlueStone. The estimates in this report
have been prepared in accordance with the definitions and
guidelines of the U.S. Securities and Exchange Commission
(SEC) and, with the exception of the exclusion of future income
taxes, conform to the FASB Accounting Standards Codification
Topic 932, Extractive Activities Oil and Gas.
Definitions are presented immediately following this letter. As
specified by BlueStone, all of these proved reserves will be
contributed to Memorial Production Partners LP (Memorial) at the
closing of its anticipated Master Limited Partnership initial
public offering. This report has been prepared for
BlueStones use in the upcoming Master Limited Partnership
transaction; in our opinion, the assumptions, data, methods, and
procedures used in the preparation of this report are
appropriate for such purpose.
We estimate the net reserves and future net revenue to the
BlueStone interest in these properties, as of December 31,
2010, to be:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Reserves
|
|
|
Future Net Revenue ($)
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
|
|
Present Worth
|
|
Category
|
|
(Barrels)
|
|
|
(MCF)
|
|
|
Total
|
|
|
at 10%
|
|
|
Proved Developed Producing
|
|
|
243,205
|
|
|
|
106,668,195
|
|
|
|
250,009,600
|
|
|
|
139,071,100
|
|
Proved Developed Non-Producing
|
|
|
180,410
|
|
|
|
40,003,477
|
|
|
|
101,986,500
|
|
|
|
41,119,900
|
|
Proved Undeveloped
|
|
|
62,635
|
|
|
|
22,571,840
|
|
|
|
42,361,800
|
|
|
|
8,975,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
|
486,251
|
|
|
|
169,243,516
|
|
|
|
394,357,800
|
|
|
|
189,166,200
|
|
Totals may not add because of rounding.
The oil reserves shown include crude oil and condensate. Oil
volumes are expressed in barrels that are equivalent to 42
United States gallons. Gas volumes are expressed in thousands of
cubic feet (MCF) at standard temperature and pressure bases.
|
|
4500
Thanksgiving
Tower
1601 Elm
Street Dallas, Texas
75201-4754
|
nsai@nsai-petro.com
|
Ph.
214-969-5401
Fax:
214-969-5411
|
|
1221
Lamar Street, Suite
1200
Houston,
Texas
77010-3072
|
netherlandsewell.com
|
Ph.
713-654-4950
fax:
713-654-4951
C-1
The estimates shown in this report are for proved reserves. As
requested, probable and possible reserves that exist for these
properties have not been included. This report does not include
any value that could be attributed to interests in undeveloped
acreage beyond those tracts for which undeveloped reserves have
been estimated. Reserves categorization conveys the relative
degree of certainty; reserves subcategorization is based on
development and production status. The estimates of reserves and
future revenue included herein have not been adjusted for risk.
Future gross revenue to the BlueStone interest is prior to
deducting state production taxes and ad valorem taxes. Future
net revenue is after deductions for these taxes, future capital
costs, and operating expenses but before consideration of any
income taxes. The future net revenue has been discounted at an
annual rate of 10 percent to determine its present worth,
which is shown to indicate the effect of time on the value of
money. Future net revenue presented in this report, whether
discounted or undiscounted, should not be construed as being the
fair market value of the properties.
For the purposes of this report, we did not perform any field
inspection of the properties, nor did we examine the mechanical
operation or condition of the wells and facilities. We have not
investigated possible environmental liability related to the
properties; therefore, our estimates do not include any costs
due to such possible liability. Also, our estimates do not
include any salvage value for the lease and well equipment or
the cost of abandoning the properties.
Prices used in this report are based on the
12-month
unweighted arithmetic average of the
first-day-of-the-month
price for each month in the period January through December
2010. For oil volumes, the average West Texas Intermediate
posted price of $75.96 per barrel is adjusted by field for
quality, transportation fees, and regional price differentials.
For gas volumes, the average Henry Hub spot price of $4.376 per
MMBTU is adjusted by field for energy content, transportation
fees, and regional price differentials. All prices are held
constant throughout the lives of the properties. For the proved
reserves, the average adjusted product prices weighted by
production over the remaining lives of the properties are $74.59
per barrel of oil and $4.495 per MCF of gas.
Lease and well operating costs used in this report are based on
operating expense records of BlueStone. For nonoperated
properties, these costs include the per-well overhead expenses
allowed under joint operating agreements along with estimates of
costs to be incurred at and below the district and field levels.
As requested, lease and well operating costs for the operated
properties are limited to direct lease- and field-level costs
and BlueStones estimate of the portion of its headquarters
general and administrative overhead expenses necessary to
operate the properties. Lease and well operating costs are held
constant throughout the lives of the properties. Capital costs
are included as required for workovers, new development wells,
and production equipment. The future capital costs are held
constant to the date of expenditure.
We have made no investigation of potential gas volume and value
imbalances resulting from overdelivery or underdelivery to the
BlueStone interest. Therefore, our estimates of reserves and
future revenue do not include adjustments for the settlement of
any such imbalances; our projections are based on BlueStone
receiving its net revenue interest share of estimated future
gross gas production.
The reserves shown in this report are estimates only and should
not be construed as exact quantities. Proved reserves are those
quantities of oil and gas which, by analysis of engineering and
geoscience data, can be estimated with reasonable certainty to
be economically producible. Estimates of reserves may increase
or decrease as a result of market conditions, future operations,
changes in regulations, or actual reservoir performance. In
addition to the primary economic assumptions discussed herein,
our estimates are based on certain assumptions including, but
not limited to, that the properties will be developed consistent
with current development plans, that the properties will be
operated in a prudent manner, that no governmental regulations
or controls will be put in place that would impact the ability
of the interest owner to recover the reserves, and that our
projections of future production will prove consistent with
actual performance. If the reserves are recovered, the revenues
therefrom and the costs related thereto could be more or less
than the estimated
C-2
amounts. Because of governmental policies and uncertainties of
supply and demand, the sales rates, prices received for the
reserves, and costs incurred in recovering such reserves may
vary from assumptions made while preparing this report.
For the purposes of this report, we used technical and economic
data including, but not limited to, well logs, geologic maps,
seismic data, well test data, production data, historical price
and cost information, and property ownership interests. The
reserves in this report have been estimated using deterministic
methods; these estimates have been prepared in accordance with
the Standards Pertaining to the Estimating and Auditing of Oil
and Gas Reserves Information promulgated by the Society of
Petroleum Engineers (SPE Standards). We used standard
engineering and geoscience methods, or a combination of methods,
including performance analysis, volumetric analysis, and
analogy, that we considered to be appropriate and necessary to
categorize and estimate reserves in accordance with SEC
definitions and guidelines. As in all aspects of oil and gas
evaluation, there are uncertainties inherent in the
interpretation of engineering and geoscience data; therefore,
our conclusions necessarily represent only informed professional
judgment.
The data used in our estimates were obtained from BlueStone,
public data sources, and the nonconfidential files of
Netherland, Sewell & Associates, Inc. (NSAI) and were
accepted as accurate. Supporting geoscience, performance, and
work data are on file in our office. The titles to the
properties have not been examined by NSAI, nor has the actual
degree or type of interest owned been independently confirmed.
The technical persons responsible for preparing the estimates
presented herein meet the requirements regarding qualifications,
independence, objectivity, and confidentiality set forth in the
SPE Standards. We are independent petroleum engineers,
geologists, geophysicists, and petrophysicists; we do not own an
interest in these properties nor are we employed on a contingent
basis.
Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
|
|
|
|
By:
|
/s/ C.H.
(Scott) Rees III
|
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer
|
|
|
By: /s/ Richard
B. Talley, Jr.
Richard
B. Talley, Jr., P.E. 102425
Vice President
|
|
By: /s/ David
E. Nice
David
E. Nice, P.G. 346
Vice President
|
|
|
|
Date Signed: June 17, 2011
|
|
Date Signed: June 17, 2011
|
RBT:EBL
Please be advised that the digital
document you are viewing is provided by Netherland,
Sewell & Associates, Inc. (NSAI) as a convenience to
our clients. The digital document is intended to be
substantively the same as the original signed document
maintained by NSAI. The digital document is subject to the
parameters, limitations, and conditions stated in the original
document. In the event of any differences between the digital
document and the original document, the original document shall
control and supersede the digital document.
C-3
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission
Regulation S-X
Section 210.4-10(a)
The following definitions are set forth in U.S. Securities
and Exchange Commission (SEC)
Regulation S-X
Section 210.4-10(a).
Also included is supplemental information from (1) the 2007
Petroleum Resources Management System approved by the Society of
Petroleum Engineers, (2) the FASB Accounting Standards
Codification Topic 932, Extractive Activities Oil
and Gas, and (3) the SECs Compliance and Disclosure
Interpretations.
(1) Acquisition of properties. Costs
incurred to purchase, lease or otherwise acquire a property,
including costs of lease bonuses and options to purchase or
lease properties, the portion of costs applicable to minerals
when land including mineral rights is purchased in fee,
brokers fees, recording fees, legal costs, and other costs
incurred in acquiring properties.
(2) Analogous reservoir. Analogous
reservoirs, as used in resources assessments, have similar rock
and fluid properties, reservoir conditions (depth, temperature,
and pressure) and drive mechanisms, but are typically at a more
advanced stage of development than the reservoir of interest and
thus may provide concepts to assist in the interpretation of
more limited data and estimation of recovery. When used to
support proved reserves, an analogous reservoir
refers to a reservoir that shares the following characteristics
with the reservoir of interest:
|
|
|
|
(i)
|
Same geological formation (but not necessarily in pressure
communication with the reservoir of interest);
|
|
|
|
|
(ii)
|
Same environment of deposition;
|
|
|
|
|
(iii)
|
Similar geological structure; and
|
|
|
|
|
(iv)
|
Same drive mechanism.
|
Instruction to paragraph (a)(2): Reservoir
properties must, in the aggregate, be no more favorable in the
analog than in the reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred
to as natural bitumen, is petroleum in a solid or semi-solid
state in natural deposits with a viscosity greater than 10,000
centipoise measured at original temperature in the deposit and
atmospheric pressure, on a gas free basis. In its natural state
it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture
of hydrocarbons that exists in the gaseous phase at original
reservoir temperature and pressure, but that, when produced, is
in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of
estimating reserves or resources is called deterministic when a
single value for each parameter (from the geoscience,
engineering, or economic data) in the reserves calculation is
used in the reserves estimation procedure.
(6) Developed oil and gas
reserves. Developed oil and gas reserves are
reserves of any category that can be expected to be recovered:
|
|
|
|
(i)
|
Through existing wells with existing equipment and operating
methods or in which the cost of the required equipment is
relatively minor compared to the cost of a new well; and
|
|
|
|
|
(ii)
|
Through installed extraction equipment and infrastructure
operational at the time of the reserves estimate if the
extraction is by means not involving a well.
|
Definitions - Page 1 of 10
C-4
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission
Regulation S-X
Section 210.4-10(a)
|
|
|
|
|
|
Supplemental definitions from the 2007 Petroleum Resources
Management System:
|
|
Developed Producing Reserves Developed Producing
Reserves are expected to be recovered from completion intervals
that are open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after
the improved recovery project is in operation.
Developed Non-Producing Reserves Developed
Non-Producing Reserves include shut-in and behind-pipe Reserves.
Shut-in Reserves are expected to be recovered from
(1) completion intervals which are open at the time of the
estimate but which have not yet started producing,
(2) wells which were shut-in for market conditions or
pipeline connections, or (3) wells not capable of
production for mechanical reasons. Behind-pipe Reserves are
expected to be recovered from zones in existing wells which will
require additional completion work or future recompletion prior
to start of production. In all cases, production can be
initiated or restored with relatively low expenditure compared
to the cost of drilling a new well.
(7) Development costs. Costs incurred to
obtain access to proved reserves and to provide facilities for
extracting, treating, gathering and storing the oil and gas.
More specifically, development costs, including depreciation and
applicable operating costs of support equipment and facilities
and other costs of development activities, are costs incurred to:
|
|
|
|
(i)
|
Gain access to and prepare well locations for drilling,
including surveying well locations for the purpose of
determining specific development drilling sites, clearing
ground, draining, road building, and relocating public roads,
gas lines, and power lines, to the extent necessary in
developing the proved reserves.
|
|
|
|
|
(ii)
|
Drill and equip development wells, development-type
stratigraphic test wells, and service wells, including the costs
of platforms and of well equipment such as casing, tubing,
pumping equipment, and the wellhead assembly.
|
|
|
|
|
(iii)
|
Acquire, construct, and install production facilities such as
lease flow lines, separators, treaters, heaters, manifolds,
measuring devices, and production storage tanks, natural gas
cycling and processing plants, and central utility and waste
disposal systems.
|
|
|
|
|
(iv)
|
Provide improved recovery systems.
|
(8) Development project. A development
project is the means by which petroleum resources are brought to
the status of economically producible. As examples, the
development of a single reservoir or field, an incremental
development in a producing field, or the integrated development
of a group of several fields and associated facilities with a
common ownership may constitute a development project.
(9) Development well. A well drilled
within the proved area of an oil or gas reservoir to the depth
of a stratigraphic horizon known to be productive.
(10) Economically producible. The term
economically producible, as it relates to a resource, means a
resource which generates revenue that exceeds, or is reasonably
expected to exceed, the costs of the operation. The value of the
products that generate revenue shall be determined at the
terminal point of oil and gas producing activities as defined in
paragraph (a)(16) of this section.
(11) Estimated ultimate recovery
(EUR). Estimated ultimate recovery is the sum of
reserves remaining as of a given date and cumulative production
as of that date.
Definitions - Page 2 of 10
C-5
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission
Regulation S-X
Section 210.4-10(a)
(12) Exploration costs. Costs incurred in
identifying areas that may warrant examination and in examining
specific areas that are considered to have prospects of
containing oil and gas reserves, including costs of drilling
exploratory wells and exploratory-type stratigraphic test wells.
Exploration costs may be incurred both before acquiring the
related property (sometimes referred to in part as prospecting
costs) and after acquiring the property. Principal types of
exploration costs, which include depreciation and applicable
operating costs of support equipment and facilities and other
costs of exploration activities, are:
|
|
|
|
(i)
|
Costs of topographical, geographical and geophysical studies,
rights of access to properties to conduct those studies, and
salaries and other expenses of geologists, geophysical crews,
and others conducting those studies. Collectively, these are
sometimes referred to as geological and geophysical or
G&G costs.
|
|
|
|
|
(ii)
|
Costs of carrying and retaining undeveloped properties, such as
delay rentals, ad valorem taxes on properties, legal costs for
title defense, and the maintenance of land and lease records.
|
|
|
|
|
(iii)
|
Dry hole contributions and bottom hole contributions.
|
|
|
|
|
(iv)
|
Costs of drilling and equipping exploratory wells.
|
|
|
|
|
(v)
|
Costs of drilling exploratory-type stratigraphic test wells.
|
(13) Exploratory well. An exploratory
well is a well drilled to find a new field or to find a new
reservoir in a field previously found to be productive of oil or
gas in another reservoir. Generally, an exploratory well is any
well that is not a development well, an extension well, a
service well, or a stratigraphic test well as those items are
defined in this section.
(14) Extension well. An extension well is
a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of a
single reservoir or multiple reservoirs all grouped on or
related to the same individual geological structural feature
and/or
stratigraphic condition. There may be two or more reservoirs in
a field which are separated vertically by intervening impervious
strata, or laterally by local geologic barriers, or by both.
Reservoirs that are associated by being in overlapping or
adjacent fields may be treated as a single or common operational
field. The geological terms structural feature and
stratigraphic condition are intended to identify
localized geological features as opposed to the broader terms of
basins, trends, provinces, plays, areas-of-interest, etc.
(16) Oil and gas producing activities.
|
|
|
|
(i)
|
Oil and gas producing activities include:
|
|
|
|
|
(A)
|
The search for crude oil, including condensate and natural gas
liquids, or natural gas (oil and gas) in their
natural states and original locations;
|
|
|
(B)
|
The acquisition of property rights or properties for the purpose
of further exploration or for the purpose of removing the oil or
gas from such properties;
|
|
|
(C)
|
The construction, drilling, and production activities necessary
to retrieve oil and gas from their natural reservoirs, including
the acquisition, construction, installation, and maintenance of
field gathering and storage systems, such as:
|
|
|
|
|
(1)
|
Lifting the oil and gas to the surface; and
|
Definitions - Page 3 of 10
C-6
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission
Regulation S-X
Section 210.4-10(a)
|
|
|
|
(2)
|
Gathering, treating, and field processing (as in the case of
processing gas to extract liquid hydrocarbons); and
|
|
|
|
|
(D)
|
Extraction of saleable hydrocarbons, in the solid, liquid, or
gaseous state, from oil sands, shale, coalbeds, or other
nonrenewable natural resources which are intended to be upgraded
into synthetic oil or gas, and activities undertaken with a view
to such extraction.
|
Instruction 1 to paragraph
(a)(16)(i): The oil and gas production function
shall be regarded as ending at a terminal point,
which is the outlet valve on the lease or field storage tank. If
unusual physical or operational circumstances exist, it may be
appropriate to regard the terminal point for the production
function as:
|
|
|
|
a.
|
The first point at which oil, gas, or gas liquids, natural or
synthetic, are delivered to a main pipeline, a common carrier, a
refinery, or a marine terminal; and
|
|
|
b.
|
In the case of natural resources that are intended to be
upgraded into synthetic oil or gas, if those natural resources
are delivered to a purchaser prior to upgrading, the first point
at which the natural resources are delivered to a main pipeline,
a common carrier, a refinery, a marine terminal, or a facility
which upgrades such natural resources into synthetic oil or gas.
|
Instruction 2 to paragraph
(a)(16)(i): For purposes of this paragraph
(a)(16), the term saleable hydrocarbons means hydrocarbons that
are saleable in the state in which the hydrocarbons are
delivered.
|
|
|
|
(ii)
|
Oil and gas producing activities do not include:
|
|
|
|
|
(A)
|
Transporting, refining, or marketing oil and gas;
|
|
|
(B)
|
Processing of produced oil, gas, or natural resources that can
be upgraded into synthetic oil or gas by a registrant that does
not have the legal right to produce or a revenue interest in
such production;
|
|
|
(C)
|
Activities relating to the production of natural resources other
than oil, gas, or natural resources from which synthetic oil and
gas can be extracted; or
|
|
|
(D)
|
Production of geothermal steam.
|
(17) Possible reserves. Possible reserves
are those additional reserves that are less certain to be
recovered than probable reserves.
|
|
|
|
(i)
|
When deterministic methods are used, the total quantities
ultimately recovered from a project have a low probability of
exceeding proved plus probable plus possible reserves. When
probabilistic methods are used, there should be at least a 10%
probability that the total quantities ultimately recovered will
equal or exceed the proved plus probable plus possible reserves
estimates.
|
|
|
|
|
(ii)
|
Possible reserves may be assigned to areas of a reservoir
adjacent to probable reserves where data control and
interpretations of available data are progressively less
certain. Frequently, this will be in areas where geoscience and
engineering data are unable to define clearly the area and
vertical limits of commercial production from the reservoir by a
defined project.
|
|
|
|
|
(iii)
|
Possible reserves also include incremental quantities associated
with a greater percentage recovery of the hydrocarbons in place
than the recovery quantities assumed for probable reserves.
|
Definitions - Page 4 of 10
C-7
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission
Regulation S-X
Section 210.4-10(a)
|
|
|
|
(iv)
|
The proved plus probable and proved plus probable plus possible
reserves estimates must be based on reasonable alternative
technical and commercial interpretations within the reservoir or
subject project that are clearly documented, including
comparisons to results in successful similar projects.
|
|
|
|
|
(v)
|
Possible reserves may be assigned where geoscience and
engineering data identify directly adjacent portions of a
reservoir within the same accumulation that may be separated
from proved areas by faults with displacement less than
formation thickness or other geological discontinuities and that
have not been penetrated by a wellbore, and the registrant
believes that such adjacent portions are in communication with
the known (proved) reservoir. Possible reserves may be assigned
to areas that are structurally higher or lower than the proved
area if these areas are in communication with the proved
reservoir.
|
|
|
|
|
(vi)
|
Pursuant to paragraph (a)(22)(iii) of this section, where direct
observation has defined a highest known oil (HKO) elevation and
the potential exists for an associated gas cap, proved oil
reserves should be assigned in the structurally higher portions
of the reservoir above the HKO only if the higher contact can be
established with reasonable certainty through reliable
technology. Portions of the reservoir that do not meet this
reasonable certainty criterion may be assigned as probable and
possible oil or gas based on reservoir fluid properties and
pressure gradient interpretations.
|
(18) Probable reserves. Probable reserves
are those additional reserves that are less certain to be
recovered than proved reserves but which, together with proved
reserves, are as likely as not to be recovered.
|
|
|
|
(i)
|
When deterministic methods are used, it is as likely as not that
actual remaining quantities recovered will exceed the sum of
estimated proved plus probable reserves. When probabilistic
methods are used, there should be at least a 50% probability
that the actual quantities recovered will equal or exceed the
proved plus probable reserves estimates.
|
|
|
|
|
(ii)
|
Probable reserves may be assigned to areas of a reservoir
adjacent to proved reserves where data control or
interpretations of available data are less certain, even if the
interpreted reservoir continuity of structure or productivity
does not meet the reasonable certainty criterion. Probable
reserves may be assigned to areas that are structurally higher
than the proved area if these areas are in communication with
the proved reservoir.
|
|
|
|
|
(iii)
|
Probable reserves estimates also include potential incremental
quantities associated with a greater percentage recovery of the
hydrocarbons in place than assumed for proved reserves.
|
|
|
|
|
(iv)
|
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of
this section.
|
(19) Probabilistic estimate. The method
of estimation of reserves or resources is called probabilistic
when the full range of values that could reasonably occur for
each unknown parameter (from the geoscience and engineering
data) is used to generate a full range of possible outcomes and
their associated probabilities of occurrence.
(20) Production costs.
|
|
|
|
(i)
|
Costs incurred to operate and maintain wells and related
equipment and facilities, including depreciation and applicable
operating costs of support equipment and facilities and other
costs of
|
Definitions - Page 5 of 10
C-8
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission
Regulation S-X
Section 210.4-10(a)
|
|
|
|
|
operating and maintaining those wells and related equipment and
facilities. They become part of the cost of oil and gas
produced. Examples of production costs (sometimes called lifting
costs) are:
|
|
|
|
|
(A)
|
Costs of labor to operate the wells and related equipment and
facilities.
|
|
|
(B)
|
Repairs and maintenance.
|
|
|
(C)
|
Materials, supplies, and fuel consumed and supplies utilized in
operating the wells and related equipment and facilities.
|
|
|
(D)
|
Property taxes and insurance applicable to proved properties and
wells and related equipment and facilities.
|
|
|
|
|
(ii)
|
Some support equipment or facilities may serve two or more oil
and gas producing activities and may also serve transportation,
refining, and marketing activities. To the extent that the
support equipment and facilities are used in oil and gas
producing activities, their depreciation and applicable
operating costs become exploration, development or production
costs, as appropriate. Depreciation, depletion, and amortization
of capitalized acquisition, exploration, and development costs
are not production costs but also become part of the cost of oil
and gas produced along with production (lifting) costs
identified above.
|
(21) Proved area. The part of a property
to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved
oil and gas reserves are those quantities of oil and gas, which,
by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically
producible from a given date forward, from known
reservoirs, and under existing economic conditions, operating
methods, and government regulations prior to the
time at which contracts providing the right to operate expire,
unless evidence indicates that renewal is reasonably certain,
regardless of whether deterministic or probabilistic methods are
used for the estimation. The project to extract the hydrocarbons
must have commenced or the operator must be reasonably certain
that it will commence the project within a reasonable time.
|
|
|
|
(i)
|
The area of the reservoir considered as proved includes:
|
|
|
|
|
(A)
|
The area identified by drilling and limited by fluid contacts,
if any, and
|
|
|
(B)
|
Adjacent undrilled portions of the reservoir that can, with
reasonable certainty, be judged to be continuous with it and to
contain economically producible oil or gas on the basis of
available geoscience and engineering data.
|
|
|
|
|
(ii)
|
In the absence of data on fluid contacts, proved quantities in a
reservoir are limited by the lowest known hydrocarbons (LKH) as
seen in a well penetration unless geoscience, engineering, or
performance data and reliable technology establishes a lower
contact with reasonable certainty.
|
|
|
|
|
(iii)
|
Where direct observation from well penetrations has defined a
highest known oil (HKO) elevation and the potential exists for
an associated gas cap, proved oil reserves may be assigned in
the structurally higher portions of the reservoir only if
geoscience, engineering, or performance data and reliable
technology establish the higher contact with reasonable
certainty.
|
Definitions - Page 6 of 10
C-9
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission
Regulation S-X
Section 210.4-10(a)
|
|
|
|
(iv)
|
Reserves which can be produced economically through application
of improved recovery techniques (including, but not limited to,
fluid injection) are included in the proved classification when:
|
|
|
|
|
(A)
|
Successful testing by a pilot project in an area of the
reservoir with properties no more favorable than in the
reservoir as a whole, the operation of an installed program in
the reservoir or an analogous reservoir, or other evidence using
reliable technology establishes the reasonable certainty of the
engineering analysis on which the project or program was
based; and
|
|
|
(B)
|
The project has been approved for development by all necessary
parties and entities, including governmental entities.
|
|
|
|
|
(v)
|
Existing economic conditions include prices and costs at which
economic producibility from a reservoir is to be determined. The
price shall be the average price during the
12-month
period prior to the ending date of the period covered by the
report, determined as an unweighted arithmetic average of the
first-day-of-the-month
price for each month within such period, unless prices are
defined by contractual arrangements, excluding escalations based
upon future conditions.
|
(23) Proved properties. Properties with
proved reserves.
(24) Reasonable certainty. If
deterministic methods are used, reasonable certainty means a
high degree of confidence that the quantities will be recovered.
If probabilistic methods are used, there should be at least a
90% probability that the quantities actually recovered will
equal or exceed the estimate. A high degree of confidence exists
if the quantity is much more likely to be achieved than not,
and, as changes due to increased availability of geoscience
(geological, geophysical, and geochemical), engineering, and
economic data are made to estimated ultimate recovery (EUR) with
time, reasonably certain EUR is much more likely to increase or
remain constant than to decrease.
(25) Reliable technology. Reliable
technology is a grouping of one or more technologies (including
computational methods) that has been field tested and has been
demonstrated to provide reasonably certain results with
consistency and repeatability in the formation being evaluated
or in an analogous formation.
(26) Reserves. Reserves are estimated
remaining quantities of oil and gas and related substances
anticipated to be economically producible, as of a given date,
by application of development projects to known accumulations.
In addition, there must exist, or there must be a reasonable
expectation that there will exist, the legal right to produce or
a revenue interest in the production, installed means of
delivering oil and gas or related substances to market, and all
permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not
be assigned to adjacent reservoirs isolated by major,
potentially sealing, faults until those reservoirs are
penetrated and evaluated as economically producible. Reserves
should not be assigned to areas that are clearly separated from
a known accumulation by a non-productive reservoir (i.e.,
absence of reservoir, structurally low reservoir, or negative
test results). Such areas may contain prospective resources
(i.e., potentially recoverable resources from undiscovered
accumulations).
Definitions - Page 7 of 10
C-10
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission
Regulation S-X
Section 210.4-10(a)
Excerpted from the FASB Accounting Standards Codification
Topic 932, Extractive Activities Oil and Gas:
932-235-50-30
A standardized measure of discounted future net cash flows
relating to an entitys interests in both of the following
shall be disclosed as of the end of the year:
|
|
|
|
|
a.
|
Proved oil and gas reserves (see
paragraphs 932-235-50-3
through
50-11B)
|
|
|
|
|
|
|
b.
|
Oil and gas subject to purchase under long-term supply,
purchase, or similar agreements and contracts in which the
entity participates in the operation of the properties on which
the oil or gas is located or otherwise serves as the producer of
those reserves (see
paragraph 932-235-50-7).
|
|
The standardized measure of discounted future net cash flows
relating to those two types of interests in reserves may be
combined for reporting purposes.
932-235-50-31
All of the following information shall be disclosed in the
aggregate and for each geographic area for which reserve
quantities are disclosed in accordance with
paragraphs 932-235-50-3
through
50-11B:
|
|
|
|
|
a.
|
Future cash inflows. These shall be computed by applying
prices used in estimating the entitys proved oil and gas
reserves to the year-end quantities of those reserves. Future
price changes shall be considered only to the extent provided by
contractual arrangements in existence at year-end.
|
|
|
|
|
|
|
b.
|
Future development and production costs. These costs shall be
computed by estimating the expenditures to be incurred in
developing and producing the proved oil and gas reserves at the
end of the year, based on year-end costs and assuming
continuation of existing economic conditions. If estimated
development expenditures are significant, they shall be
presented separately from estimated production costs.
|
|
|
|
c.
|
Future income tax expenses. These expenses shall be computed
by applying the appropriate year-end statutory tax rates, with
consideration of future tax rates already legislated, to the
future pretax net cash flows relating to the entitys
proved oil and gas reserves, less the tax basis of the
properties involved. The future income tax expenses shall give
effect to tax deductions and tax credits and allowances relating
to the entitys proved oil and gas reserves.
|
|
|
|
|
|
|
d.
|
Future net cash flows. These amounts are the result of
subtracting future development and production costs and future
income tax expenses from future cash inflows.
|
|
|
|
|
|
|
e.
|
Discount. This amount shall be derived from using a discount
rate of 10 percent a year to reflect the timing of the
future net cash flows relating to proved oil and gas
reserves.
|
|
|
|
|
|
|
f.
|
Standardized measure of discounted future net cash flows.
This amount is the future net cash flows less the computed
discount.
|
|
(27) Reservoir. A porous and permeable
underground formation containing a natural accumulation of
producible oil
and/or gas
that is confined by impermeable rock or water barriers and is
individual and separate from other reservoirs.
(28) Resources. Resources are quantities
of oil and gas estimated to exist in naturally occurring
accumulations. A portion of the resources may be estimated to be
recoverable, and another portion may be considered to be
unrecoverable. Resources include both discovered and
undiscovered accumulations.
Definitions - Page 8 of 10
C-11
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission
Regulation S-X
Section 210.4-10(a)
(29) Service well. A well drilled or
completed for the purpose of supporting production in an
existing field. Specific purposes of service wells include gas
injection, water injection, steam injection, air injection,
salt-water disposal, water supply for injection, observation, or
injection for in-situ combustion.
(30) Stratigraphic test well. A
stratigraphic test well is a drilling effort, geologically
directed, to obtain information pertaining to a specific
geologic condition. Such wells customarily are drilled without
the intent of being completed for hydrocarbon production. The
classification also includes tests identified as core tests and
all types of expendable holes related to hydrocarbon
exploration. Stratigraphic tests are classified as
exploratory type if not drilled in a known area or
development type if drilled in a known area.
(31) Undeveloped oil and gas
reserves. Undeveloped oil and gas reserves are
reserves of any category that are expected to be recovered from
new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion.
|
|
|
|
(i)
|
Reserves on undrilled acreage shall be limited to those directly
offsetting development spacing areas that are reasonably certain
of production when drilled, unless evidence using reliable
technology exists that establishes reasonable certainty of
economic producibility at greater distances.
|
|
|
|
|
(ii)
|
Undrilled locations can be classified as having undeveloped
reserves only if a development plan has been adopted indicating
that they are scheduled to be drilled within five years, unless
the specific circumstances, justify a longer time.
|
From the SECs Compliance and Disclosure Interpretations
(October 26, 2009):
Although several types of projects such as
constructing offshore platforms and development in urban areas,
remote locations or environmentally sensitive
locations by their nature customarily take a longer
time to develop and therefore often do justify longer time
periods, this determination must always take into consideration
all of the facts and circumstances. No particular type of
project per se justifies a longer time period, and any extension
beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether
or not circumstances justify recognizing reserves even though
development may extend past five years include, but are not
limited to, the following:
|
|
|
|
|
|
The companys level of ongoing significant development
activities in the area to be developed (for example, drilling
only the minimum number of wells necessary to maintain the lease
generally would not constitute significant development
activities);
|
|
|
|
|
The companys historical record at completing
development of comparable long-term projects;
|
|
|
|
|
The amount of time in which the company has maintained the
leases, or booked the reserves, without significant development
activities;
|
|
|
|
|
The extent to which the company has followed a previously
adopted development plan (for example, if a company has changed
its development plan several times without taking significant
steps to implement any of those plans, recognizing proved
undeveloped reserves typically would not be
appropriate); and
|
|
|
|
|
The extent to which delays in development are caused by
external factors related to the physical operating environment
(for example, restrictions on development on Federal lands, but
not
|
|
Definitions - Page 9 of 10
C-12
DEFINITIONS
OF OIL AND GAS RESERVES
Adapted
from U.S. Securities and Exchange Commission
Regulation S-X
Section 210.4-10(a)
|
|
|
|
|
|
obtaining government permits), rather than by internal
factors (for example, shifting resources to develop properties
with higher priority).
|
|
|
|
|
|
(iii)
|
Under no circumstances shall estimates for undeveloped reserves
be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual
projects in the same reservoir or an analogous reservoir, as
defined in paragraph (a)(2) of this section, or by other
evidence using reliable technology establishing reasonable
certainty.
|
(32) Unproved properties. Properties with no proved
reserves.
Definitions - Page 10 of 10
C-13
APPENDIX D
Netherland,
Sewell & Associates, Inc. Summary Reserve Report
June 17, 2011
Mr. Jay Graham
WHT Energy Partners LLC
950 Echo Lane, Suite 200
Houston, Texas 77024
Dear Mr. Graham:
In accordance with your request, we have audited the estimates
prepared by WHT Energy Partners LLC (WHT), as of
December 31, 2010, of the proved reserves and future
revenue to the WHT interest in certain oil and gas properties
located in De Soto Parish, Louisiana, and Panola and Rusk
Counties, Texas. This report was prepared for use by WHT in an
upcoming Master Limited Partnership (MLP) transaction. This
audit includes all of the properties owned by WHT but only the
40 percent interest that will be conveyed to the MLP. The
100 percent interest owned by WHT was audited in our report
dated June 2, 2011. With the exception of this interest
change, we completed our evaluation on or about June 2,
2011. We have examined the estimates with respect to reserves
quantities, reserves categorization, future producing rates,
future net revenue, and the present value of such future net
revenue, using the definitions set forth in U.S. Securities
and Exchange Commission (SEC)
Regulation S-X
Rule 4-10(a).
The estimates of reserves and future revenue have been prepared
in accordance with the definitions and guidelines of the SEC
and, with the exception of the exclusion of future income taxes,
conform to the FASB Accounting Standards Codification Topic 932,
Extractive Activities Oil and Gas. This report has
been prepared for WHTs use in filing with the SEC; in our
opinion the assumptions, data, methods, and procedures used in
the preparation of this report are appropriate for such purpose.
The following table sets forth WHTs estimates of the net
reserves and future net revenue, as of December 31, 2010,
for the audited properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Reserves
|
|
|
|
|
|
Future Net Revenue (M$)
|
|
|
|
Oil
|
|
|
NGL
|
|
|
Gas
|
|
|
|
|
|
Present Worth
|
|
Category
|
|
(MBBL)
|
|
|
(MBBL)
|
|
|
(MMCF)
|
|
|
Total
|
|
|
at 10%
|
|
|
Proved Developed Producing
|
|
|
692.8
|
|
|
|
2,884.9
|
|
|
|
55,189.7
|
|
|
|
257,764.5
|
|
|
|
103,028.9
|
|
Proved Developed Behind-Pipe
|
|
|
67.0
|
|
|
|
0.0
|
|
|
|
3,735.2
|
|
|
|
13,274.9
|
|
|
|
7,476.1
|
|
Proved Undeveloped
|
|
|
177.4
|
|
|
|
1,167.4
|
|
|
|
23,681.5
|
|
|
|
72,101.6
|
|
|
|
11,800.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
|
937.2
|
|
|
|
4,052.3
|
|
|
|
82,606.3
|
|
|
|
343,141.0
|
|
|
|
122,305.7
|
|
Totals may not add because of rounding.
The oil reserves shown include crude oil and condensate. Oil and
natural gas liquids (NGL) volumes are expressed in thousands of
barrels (MBBL); a barrel is equivalent to 42 United States
gallons. Gas volumes are expressed in millions of cubic feet
(MMCF) at standard temperature and pressure bases.
|
|
4500
Thanksgiving
Tower
1601 Elm
Street Dallas,
Texas
75201-4754
|
nsai@nsai-petro.com
|
Ph.
214-969-5401
Fax:
214-969-5411
|
|
1221
Lamar Street, Suite
1200
Houston,
Texas
77010-3072
|
netherlandsewell.com
|
Ph.
713-654-4950
fax:
713-654-4951
D-1
When compared on a
lease-by-lease
basis, some of the estimates of WHT are greater and some are
less than the estimates of Netherland, Sewell &
Associates, Inc. (NSAI). However, in our opinion the estimates
of WHTs proved reserves and future revenue shown herein
are, in the aggregate, reasonable and have been prepared in
accordance with the Standards Pertaining to the Estimating and
Auditing of Oil and Gas Reserves Information promulgated by the
Society of Petroleum Engineers (SPE Standards). Additionally,
these estimates are within the recommended 10 percent
tolerance threshold set forth in the SPE Standards. We are
satisfied with the methods and procedures used by WHT in
preparing the December 31, 2010, estimates of reserves and
future revenue, and we saw nothing of an unusual nature that
would cause us to take exception with the estimates, in the
aggregate, as prepared by WHT.
The estimates shown herein are for proved reserves. WHTs
estimates do not include probable or possible reserves that may
exist for these properties, nor do they include any value for
undeveloped acreage beyond those tracts for which undeveloped
reserves have been estimated. Reserves categorization conveys
the relative degree of certainty; reserves subcategorization is
based on development and production status. The estimates of
reserves and future revenue included herein have not been
adjusted for risk.
Prices used by WHT are based on the
12-month
unweighted arithmetic average of the
first-day-of-the-month
price for each month in the period January through December
2010. For oil and NGL volumes, the average West Texas
Intermediate posted price of $75.96 per barrel is adjusted by
lease for quality, transportation fees, and a regional price
differential. For gas volumes, the average Henry Hub spot price
of $4.376 per MMBTU is adjusted by lease for energy content,
compression charges, transportation fees, and regional price
differentials. All prices are held constant throughout the lives
of the properties. The average adjusted product prices weighted
by production over the remaining lives of the properties are
$74.43 per barrel of oil, $34.18 per barrel of NGL, and $4.12
per MCF of gas.
Lease and well operating costs used by WHT are based on
historical operating expense records. These costs include the
per-well overhead expenses allowed under joint operating
agreements along with estimates of costs to be incurred at and
below the district and field levels. Headquarters general and
administrative overhead expenses of WHT are included to the
extent that they are required to operate the properties. Lease
and well operating costs are held constant throughout the lives
of the properties. WHTs estimates of capital costs are
included as required for workovers, new development wells, and
production equipment. The future capital costs are held constant
to the date of expenditure.
The reserves shown in this report are estimates only and should
not be construed as exact quantities. Proved reserves are those
quantities of oil and gas which, by analysis of engineering and
geoscience data, can be estimated with reasonable certainty to
be economically producible. Estimates of reserves may increase
or decrease as a result of market conditions, future operations,
changes in regulations, or actual reservoir performance. In
addition to the primary economic assumptions discussed herein,
estimates of WHT and NSAI are based on certain assumptions
including, but not limited to, that the properties will be
developed consistent with current development plans, that the
properties will be operated in a prudent manner, that no
governmental regulations or controls will be put in place that
would impact the ability of the interest owner to recover the
reserves, and that projections of future production will prove
consistent with actual performance. If the reserves are
recovered, the revenues therefrom and the costs related thereto
could be more or less than the estimated amounts. Because of
governmental policies and uncertainties of supply and demand,
the sales rates, prices received for the reserves, and costs
incurred in recovering such reserves may vary from assumptions
made while preparing these estimates.
It should be understood that our audit does not constitute a
complete reserves study of the audited oil and gas properties.
Our audit consisted primarily of substantive testing, wherein we
conducted a detailed review of all properties. In the conduct of
our audit, we have not independently verified the accuracy and
completeness of information and data furnished by WHT with
respect to ownership interests, oil and gas production, well
test data, historical costs of operation and development,
product prices, or any agreements relating to current
D-2
and future operations of the properties and sales of production.
However, if in the course of our examination something came to
our attention that brought into question the validity or
sufficiency of any such information or data, we did not rely on
such information or data until we had satisfactorily resolved
our questions relating thereto or had independently verified
such information or data. Our audit did not include a review of
WHTs overall reserves management processes and practices.
We used standard engineering and geoscience methods, or a
combination of methods, including performance analysis,
volumetric analysis, and analogy that we considered to be
appropriate and necessary to establish the conclusions set forth
herein. As in all aspects of oil and gas evaluation, there are
uncertainties inherent in the interpretation of engineering and
geoscience data; therefore, our conclusions necessarily
represent only informed professional judgment.
Supporting data documenting this audit, along with data provided
by WHT, are on file in our office. The technical persons
responsible for conducting this audit meet the requirements
regarding qualifications, independence, objectivity, and
confidentiality set forth in the SPE Standards. We are
independent petroleum engineers, geologists, geophysicists, and
petrophysicists; we do not own an interest in these properties
nor are we employed on a contingent basis.
Sincerely,
NETHERLAND, SEWELL & ASSOCIATES,
INC.
Texas Registered Engineering Firm F-2699
|
|
|
|
By:
|
/s/ C.H.
(Scott) Rees III, P.E.
|
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer
|
|
|
|
By:
|
/s/ Justin
S. Hamilton, P.E. 104999
|
Justin S. Hamilton, P.E. 104999
Vice President
Date Signed: June 17, 2011
JSH:JLO
D-3
APPENDIX E
Miller
and Lents, Ltd. Summary of January 1, 2011
Reserves
May 24,
2011
Mr. Donald P. Gann, Jr.
COO/Managing Partner
Classic Hydrocarbons Holdings, LP
One Ridgmar Centre
6500 West Freeway, Suite 222
Fort Worth, TX 76116
|
|
|
Re:
|
|
Reserves, Resources, and
Future Net Revenues
As of January 1, 2011
|
Dear Mr. Gann:
As requested, Miller and Lents, Ltd. (MLL) estimated the
reserves as of January 1, 2011, and projected the future
net revenues attributable to the interests of Classic
Hydrocarbons Holdings, LP (Classic) in certain oil and gas
properties located in East Texas. This report was prepared for
use by Classic in an upcoming Master Limited Partnership
transaction and was completed on May 24, 2011. Reserves and
future net revenues estimates are for the specific group of
properties which are to be included in the transaction and are
the same estimates as those included in our report for Classic
dated March 4, 2011. The only change made to our prior
evaluation was higher overhead charges which were specified by
Classic. No additional well data were reviewed. The aggregate
results of MLL evaluations, using constant product prices and
costs, are summarized below. In this table and for some
summaries herein, MLL combined oil, condensate, and natural gas
liquids (NGL) together as hydrocarbon liquids.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Reserves
|
|
|
Future Net Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted at
|
|
|
|
Liquids,
|
|
|
Gas,
|
|
|
Undiscounted,
|
|
|
10% Per Year,
|
|
Reserves Category
|
|
MBbls.
|
|
|
MMcf
|
|
|
M$
|
|
|
M$
|
|
|
Proved Developed Producing
|
|
|
738.8
|
|
|
|
29,156.5
|
|
|
|
107,926.3
|
|
|
|
45,616.6
|
|
Proved Developed Nonproducing
|
|
|
2.2
|
|
|
|
963.9
|
|
|
|
1,476.9
|
|
|
|
468.8
|
|
Proved Undeveloped
|
|
|
286.8
|
|
|
|
3,705.8
|
|
|
|
20,566.4
|
|
|
|
6,602.9
|
|
Total Proved Reserves
|
|
|
1,027.8
|
|
|
|
33,826.2
|
|
|
|
129,669.6
|
|
|
|
52,688.3
|
|
Definitions
The reserves and resources reported herein conform to the
standards of the Petroleum Resources Management System, which
was prepared by the Oil and Gas Reserves Committee of the
Society of Petroleum Engineers (SPE). The document (SPE-PRMS)
was reviewed and jointly sponsored by the World Petroleum
Council, the American Association of Petroleum Geologists, and
the Society of Petroleum Evaluation Engineers. It was approved
by the SPE Board of Directors in March 2007. Definitions from
the SPE-PRMS are included in Appendix 1. The proved,
probable, and possible reserves are also in accordance
Two
Houston Center 909 Fannin Street,
Suite 1300 Houston, Texas
77010
Telephone
713-651-9455 Telefax
713-654-9914 e-mail:
mail@millerandlents.com
E-1
|
|
Mr. Donald
P. Gann, Jr.
|
May 24, 2011
|
|
|
Classic
Hydrocarbons Holdings, LP
|
Page 2
|
with the definitions contained in the Securities and Exchange
Commission (SEC)
Regulation S-X,
Rule 4-10(a)
as shown in Appendix 2.
Future net revenues as used herein are defined as the total
gross revenues less royalty, production taxes, operating costs,
and capital expenditures. Future net revenues do not include
deductions for federal income tax. The future net revenues were
discounted at 10 percent per year in accordance with SEC
guidelines to illustrate the present value of future cash flows.
Estimates of future net revenues and discounted future net
revenues are not intended and should not be interpreted to
represent fair market values for the estimated reserves.
Economic
Considerations
Constant prices were used throughout the life of production as
in an SEC-style evaluation; however, the resources included
would not be considered in an SEC report. The product prices
used for valuing the reserves herein are in accordance with
current SEC standards. The prices of $79.43 per barrel for oil,
$55.60 per barrel for NGLs, and $4.37 per MMBtu represent
the average of the
first-day-of-the-month
price for each month within the
12-month
period prior to December 31, 2010, as provided by Classic.
Price adjustments were made for each well or lease, based on
differentials between benchmark and actual prices, as estimated
by Classic, and include considerations such as gas Btu content,
oil gravity, and transportation charges. The actual average
prices used in this report for proved reserves, after
appropriate adjustments, were $77.12 per barrel for oil, $55.60
per barrel for NGLs, and $4.00 per Mcf for gas. Operating
costs as of December 31, 2010 were provided by Classic.
Costs include per-well and
per-unit of
production components that were held constant for the remaining
economic life of each property. Ad valorem and severance taxes
were projected based on recent averages, legislated rates, or
adjustments used for tight gas wells in Texas. Capital costs for
drilling and completion of future wells and recompletion of
existing wells were provided by Classic and were based on recent
experience. All future capital costs were unescalated.
Attachments
Figure 1 is a plot of historical and forecast production for
Classics properties. Incremental layers of production are
shown by reserves category. Figure 2 is a pie chart showing
total proved net reserves and discounted future net revenues by
reserves category. Figure 3 is a chart showing total proved net
reserves and gross revenues to Classic by product. Figure 4 is a
chart showing net proved reserves and associated future net
revenues by area.
Exhibits 1 through 4 are summary totals by reserves
category showing annual projections of reserves and cash flows.
Exhibit 5 is a one-line summary showing reserves and future
cash flows for each of our evaluation cases, grouped by reserves
class, reserves category, field, and well name and are sorted
alphabetically. Exhibits 6 through 89 are individual cash
flow summaries for proved developed producing wells.
Other
Considerations
The development schedule used in MLLs evaluation was
provided by Classic. Classics management gave us assurance
of their commitment and ability to perform the development work
as set forth in that schedule. The timing of production start
from development drilling and from recompletions was based on
estimates or schedules provided by Classic. Capital costs for
development wells were generally incorporated into our cash
flows two months before production start, and costs for
recompletions were incorporated at the production start date.
E-2
|
|
Mr. Donald
P. Gann, Jr.
|
May 24, 2011
|
|
|
Classic
Hydrocarbons Holdings, LP
|
Page 3
|
Classic has indicated a significant change from prior years
regarding the processing of their natural gas to recover
NGLs. Classic provided documentation of their current NGL
processing arrangements and commitments from their gas marketer
and processors for future NGL processing. They provided current
processing statements which indicate the NGL yields achieved
from gas processing and the percent of proceeds agreements in
place. Classic also provided a letter from their gas marketer
which indicates that future commitments of gas volumes would be
covered by agreements that would have similar yield and percent
of proceeds terms. Appropriate shrink factors have been applied
to the gas streams to account for the forecasted NGL production.
When compared to two MLL prior year reports, the NGL impact on
economics and values is substantial.
Future costs of abandoning facilities and wells and any future
costs of restoration of producing fields to satisfy
environmental standards were not deducted from total revenues as
such estimates are beyond the scope of this assignment.
Gas volumes are reported at the standard pressure base for the
state of Texas of 14.65 pounds per square inch.
Well counts, as reported in the various economic output tables,
actually represent completions and recompletions. Thus, a single
well bore may be counted more than once in the total well count.
In conducting this evaluation, MLL relied upon production
histories; accounting and cost data; ownership; geological,
geophysical, and engineering data; and development plans
supplied by Classic Hydrocarbons, Inc. and non-confidential data
from public records or commercial data services. These data were
accepted as represented, as verification of such data and
information was beyond the scope of this assignment.
The evaluations presented in this report, with the exceptions of
those parameters specified by others, reflect MLLs
informed judgments and are subject to the inherent uncertainties
associated with interpretation of geological, geophysical, and
engineering information. These uncertainties include, but are
not limited to, (1) the utilization of analogous or
indirect data and (2) the application of professional
judgments. Government policies and market conditions different
from those employed in this study may cause (1) the total
quantity of oil, natural gas liquids, or gas to be recovered,
(2) actual production rates, (3) prices received, or
(4) operating and capital costs to vary from those
presented in this report. At this time, MLL is not aware of any
regulations that would affect Classics ability to recover
the estimated reserves. Minor precision inconsistencies in
subtotals may exist in the report due to truncation or rounding
of aggregated values.
Miller and Lents, Ltd. is an independent oil and gas consulting
firm. No director, officer, or key employee of Miller and Lents,
Ltd. has any financial ownership in Classic Hydrocarbons, Inc.,
or any affiliate. Our compensation for the required
investigations and preparation of this report is not contingent
on the results obtained and reported, and we have not performed
other work that would affect our objectivity. Production of this
report was supervised by Carl D. Richard, an officer of the
firm, who is a licensed Professional Engineer
E-3
|
|
Mr. Donald
P. Gann, Jr.
|
May 24, 2011
|
|
|
Classic
Hydrocarbons Holdings, LP
|
Page 4
|
in the State of Texas with more than 25 years of relevant
experience and is professionally qualified in the estimation,
assessment, and evaluation of oil and gas reserves.
Very truly yours,
MILLER AND LENTS, LTD.
Texas Registered Engineering Firm
No. F-1442
CDR/eb
E-4
Common Units
Representing Limited Partner
Interests
Memorial Production Partners
LP
PRELIMINARY PROSPECTUS
,
2011
Citi
Raymond James
Wells Fargo Securities
J.P. Morgan
Through and
including ,
2011 (25 days after the commencement of this offering), all
dealers that effect transactions in our common units, whether or
not participating in this offering, may be required to deliver a
prospectus. This delivery is in addition to a dealer s
obligation to deliver a prospectus when acting as an underwriter
and with respect to their unsold allotments or subscriptions.
PART II
INFORMATION
NOT REQUIRED IN THE PROSPECTUS
|
|
Item 13.
|
Other
Expenses of Issuance and Distribution.
|
Set forth below are the expenses (other than underwriting
discounts and commissions) expected to be incurred in connection
with the issuance and distribution of the securities registered
hereby. With the exception of the SEC registration fee and the
FINRA filing fee, the amounts set forth below are estimates. The
underwriters have agreed to reimburse us for a portion of our
expenses.
|
|
|
|
|
SEC registration fee
|
|
$
|
33,379
|
|
FINRA filing fee
|
|
|
29,250
|
|
Stock exchange listing fee
|
|
|
*
|
|
Underwriter structuring fee
|
|
|
*
|
|
Printing and engraving expenses
|
|
|
*
|
|
Accounting fees and expenses
|
|
|
*
|
|
Legal fees and expenses
|
|
|
*
|
|
Transfer agent and registrar fees
|
|
|
*
|
|
Miscellaneous
|
|
|
*
|
|
|
|
|
|
|
Total
|
|
$
|
*
|
|
|
|
|
|
|
|
|
|
* |
|
To be provided by amendment. |
|
|
Item 14.
|
Indemnification
of Directors and Officers.
|
Subject to any terms, conditions or restrictions set forth in
the partnership agreement,
Section 17-108
of the Delaware Revised Uniform Limited Partnership Act empowers
a Delaware limited partnership to indemnify and hold harmless
any partner or other persons from and against all claims and
demands whatsoever. The section of the prospectus entitled
The Partnership Agreement
Indemnification discloses that we will generally indemnify
officers, directors and affiliates of our general partner to the
fullest extent permitted by the law against all losses, claims,
damages or similar events and is incorporated herein by this
reference.
We expect to enter into indemnification agreements with our
directors which will generally indemnify our directors to the
fullest extent permitted by law. As of the consummation of this
offering, our general partner will maintain director and officer
liability insurance for the benefit of its directors and
officers.
Under the omnibus agreement, we will agree to indemnify Memorial
Resource for all claims, losses and expenses attributable to the
post-closing operations of the Partnership Properties, to the
extent that such losses are not subject to Memorial
Resources indemnification obligations. Please read
Certain Relationships and Related Party
Transactions Agreements Governing the
Transactions Indemnification for a discussion
of Memorial Resources indemnification obligations.
Reference is also made to the underwriting agreement to be filed
as an exhibit to this registration statement, which provides for
the indemnification of us, our general partner, its officers and
directors, and any person who controls us or our general
partner, including indemnification for liabilities under the
Securities Act.
|
|
Item 15.
|
Recent
Sales of Unregistered Securities.
|
On April 27, 2011, in connection with the formation of
Memorial Production Partners LP, we issued (i) the 0.1%
general partner interest in us to our general partner for $1 and
(ii) the 99.9% limited partner interest in us to Memorial
Resource Development LLC for $999, in each case in an offering
exempt from registration under Section 4(2) of the
Securities Act.
II-1
There have been no other sales of unregistered securities within
the past three years.
|
|
Item 16.
|
Exhibits
and Financial Statement Schedules.
|
(a) Exhibit Index
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
1
|
.1*
|
|
|
|
Form of Underwriting Agreement
|
|
3
|
.1
|
|
|
|
Certificate of Limited Partnership of Memorial Production
Partners LP
|
|
3
|
.2
|
|
|
|
Agreement of Limited Partnership of Memorial Production Partners
LP
|
|
3
|
.3*
|
|
|
|
Form of First Amended and Restated Agreement of Limited
Partnership of Memorial Production Partners LP (included as
Appendix A to the prospectus)
|
|
3
|
.4
|
|
|
|
Certificate of Formation of Memorial Production Partners GP LLC
|
|
3
|
.5
|
|
|
|
Limited Liability Company Agreement of Memorial Production
Partners GP LLC
|
|
3
|
.6*
|
|
|
|
Form of Amended and Restated Limited Liability Company Agreement
of Memorial Production Partners GP LLC
|
|
5
|
.1*
|
|
|
|
Opinion of Akin Gump Strauss Hauer & Feld LLP as to
the legality of the securities being registered
|
|
8
|
.1*
|
|
|
|
Opinion of Akin Gump Strauss Hauer & Feld LLP relating
to tax matters
|
|
10
|
.1*
|
|
|
|
Form of Credit Agreement
|
|
10
|
.2*
|
|
|
|
Form of Contribution, Conveyance and Assumption Agreement
|
|
10
|
.3*
|
|
|
|
Form of Long-Term Incentive Plan
|
|
10
|
.4*
|
|
|
|
Form of Omnibus Agreement
|
|
21
|
.1
|
|
|
|
List of Subsidiaries of Memorial Production Partners LP
|
|
23
|
.1
|
|
|
|
Consent of KPMG LLP
|
|
23
|
.2
|
|
|
|
Consent of KPMG LLP
|
|
23
|
.3
|
|
|
|
Consent of Ernst & Young LLP
|
|
23
|
.4
|
|
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
23
|
.5
|
|
|
|
Consent of Miller and Lents, Ltd.
|
|
23
|
.6*
|
|
|
|
Consent of Akin Gump Strauss Hauer & Feld LLP
(contained in Exhibit 5.1)
|
|
23
|
.7*
|
|
|
|
Consent of Akin Gump Strauss Hauer & Feld LLP
(contained in Exhibit 8.1)
|
|
24
|
.1
|
|
|
|
Powers of Attorney (included on the signature page to this
registration statement)
|
|
99
|
.1
|
|
|
|
Netherland, Sewell & Associates, Inc. Summary of
December 31, 2010 Reserves (included as Appendix C to
the prospectus)
|
|
99
|
.2
|
|
|
|
Netherland, Sewell & Associates, Inc. Summary Reserve
Report (included as Appendix D to the prospectus)
|
|
99
|
.3
|
|
|
|
Miller and Lents, Ltd. Summary of January 1, 2011 Reserves
(included as Appendix E to the prospectus)
|
|
|
|
* |
|
To be filed by amendment. |
The undersigned registrant hereby undertakes to provide to the
underwriters at the closing specified in the underwriting
agreement certificates in such denominations and registered in
such names as required by the underwriters to permit prompt
delivery to each purchaser.
Insofar as indemnification for liabilities arising under the
Securities Act may be permitted to directors, officers and
controlling persons of the registrant pursuant to the foregoing
provisions, or otherwise, the registrant has been advised that
in the opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed in the
Securities Act and is, therefore, unenforceable. In the event
that a claim for indemnification against such liabilities (other
than the payment by the registrant of expenses incurred or paid
by a director, officer or controlling person of the registrant
in the successful defense
II-2
of any action, suit or proceeding) is asserted by such director,
officer or controlling person in connection with the securities
being registered, the registrant will, unless in the opinion of
its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the
question whether such indemnification by it is against public
policy as expressed in the Securities Act and will be governed
by the final adjudication of such issue.
The undersigned registrant hereby undertakes that:
(1) For the purpose of determining liability under the
Securities Act to any purchaser, each prospectus filed pursuant
to Rule 424(b) as part of a registration statement relating
to an offering, other than registration statements relying on
Rule 430B or other than prospectuses filed in reliance on
Rule 430A, shall be deemed to be part of and included in
the registration statement as of the date it is first used after
effectiveness. Provided, however, that no statement made in a
registration statement or prospectus that is part of the
registration statement or made in a document incorporated or
deemed incorporated by reference into the registration statement
or prospectus that is part of the registration statement will,
as to a purchaser with a time of contract of sale prior to such
first use, supersede or modify any statement that was made in
the registration statement or prospectus that was part of the
registration statement or made in any such document immediately
prior to such date of first use.
(2) For the purpose of determining liability of the
registrant under the Securities Act to any purchaser in the
initial distribution of the securities, the undersigned
registrant undertakes that in a primary offering of securities
of the undersigned registrant pursuant to this registration
statement, regardless of the underwriting method used to sell
the securities to the purchaser, if the securities are offered
or sold to such purchaser by means of any of the following
communications, the undersigned registrant will be a seller to
the purchaser and will be considered to offer or sell such
securities to such purchaser:
i. Any preliminary prospectus or prospectus of the
undersigned registrant relating to the offering required to be
filed pursuant to Rule 424;
ii. Any free writing prospectus relating to the offering
prepared by or on behalf of the undersigned registrant or used
or referred to by the undersigned registrant;
iii. The portion of any other free writing prospectus
relating to the offering containing material information about
the undersigned registrant or its securities provided by or on
behalf of the undersigned registrant; and
iv. Any other communication that is an offer in the
offering made by the undersigned registrant to the purchaser.
(3) For purposes of determining any liability under the
Securities Act, the information omitted from the form of
prospectus filed as part of this registration statement in
reliance upon Rule 430A and contained in a form of
prospectus filed by the registrant pursuant to
Rule 424(b)(1) or (4) or 497(h) under the Securities
Act shall be deemed to be part of this registration statement as
of the time it was declared effective.
(4) For the purpose of determining any liability under the
Securities Act, each post-effective amendment that contains a
form of prospectus shall be deemed to be a new registration
statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be
the initial bona fide offering thereof.
II-3
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as
amended, the registrant has duly caused this registration
statement to be signed on its behalf by the undersigned,
thereunto duly authorized, in the City of Houston, State of
Texas, on June 23, 2011.
MEMORIAL PRODUCTION PARTNERS LP
|
|
|
|
By:
|
Memorial Production Partners GP LLC, its general partner
|
|
|
By:
|
/s/ John
A. Weinzierl
|
John A. Weinzierl
President, Chief Executive Officer and
Chairman
Each person whose signature appears below appoints John A.
Weinzierl, Andrew J. Cozby and Patrick T. Nguyen, and
each of them, any of whom may act without the joinder of the
other, as his true and lawful attorneys-in-fact and agents, with
full power of substitution and re-substitution, for him and in
his name, place and stead, in any and all capacities, to sign
any and all amendments (including post-effective amendments) to
this Registration Statement and any Registration Statement
(including any amendment thereto) for this offering that is to
be effective upon filing pursuant to Rule 462(b) under the
Securities Act of 1933, as amended, and to file the same, with
all exhibits thereto, and all other documents in connection
therewith, with the Securities and Exchange Commission, granting
unto said attorneys-in-fact and agents full power and authority
to do and perform each and every act and thing requisite and
necessary to be done, as fully to all intents and purposes as he
might or would do in person, hereby ratifying and confirming all
that said attorneys-in-fact and agents or any of them or their
or his substitute and substitutes, may lawfully do or cause to
be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, as
amended, this Registration Statement has been signed below by
the following persons in the capacities and on the dates
presented.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ John
A. Weinzierl
John
A. Weinzierl
|
|
President, Chief Executive Officer and Chairman
(Principal Executive Officer)
|
|
June 23, 2011
|
|
|
|
|
|
/s/ Andrew
J. Cozby
Andrew
J. Cozby
|
|
Vice President, Finance
(Principal Financial Officer)
|
|
June 23, 2011
|
|
|
|
|
|
/s/ Patrick
T. Nguyen
Patrick
T. Nguyen
|
|
Chief Accounting Officer
(Principal Accounting Officer)
|
|
June 23, 2011
|
|
|
|
|
|
/s/ Kenneth
A. Hersh
Kenneth
A. Hersh
|
|
Director
|
|
June 23, 2011
|
II-4
EXHIBIT INDEX
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
1
|
.1*
|
|
|
|
Form of Underwriting Agreement
|
|
3
|
.1
|
|
|
|
Certificate of Limited Partnership of Memorial Production
Partners LP
|
|
3
|
.2
|
|
|
|
Agreement of Limited Partnership of Memorial Production Partners
LP
|
|
3
|
.3*
|
|
|
|
Form of First Amended and Restated Agreement of Limited
Partnership of Memorial Production Partners LP (included as
Appendix A to the prospectus)
|
|
3
|
.4
|
|
|
|
Certificate of Formation of Memorial Production Partners GP LLC
|
|
3
|
.5
|
|
|
|
Limited Liability Company Agreement of Memorial Production
Partners GP LLC
|
|
3
|
.6*
|
|
|
|
Form of Amended and Restated Limited Liability Company Agreement
of Memorial Production Partners GP LLC
|
|
5
|
.1*
|
|
|
|
Opinion of Akin Gump Strauss Hauer & Feld LLP as to
the legality of the securities being registered
|
|
8
|
.1*
|
|
|
|
Opinion of Akin Gump Strauss Hauer & Feld LLP relating
to tax matters
|
|
10
|
.1*
|
|
|
|
Form of Credit Agreement
|
|
10
|
.2*
|
|
|
|
Form of Contribution, Conveyance and Assumption Agreement
|
|
10
|
.3*
|
|
|
|
Form of Long-Term Incentive Plan
|
|
10
|
.4*
|
|
|
|
Form of Omnibus Agreement
|
|
21
|
.1
|
|
|
|
List of Subsidiaries of Memorial Production Partners LP
|
|
23
|
.1
|
|
|
|
Consent of KPMG LLP
|
|
23
|
.2
|
|
|
|
Consent of KPMG LLP
|
|
23
|
.3
|
|
|
|
Consent of Ernst & Young LLP
|
|
23
|
.4
|
|
|
|
Consent of Netherland, Sewell & Associates, Inc.
|
|
23
|
.5
|
|
|
|
Consent of Miller and Lents, Ltd.
|
|
23
|
.6*
|
|
|
|
Consent of Akin Gump Strauss Hauer & Feld LLP
(contained in Exhibit 5.1)
|
|
23
|
.7*
|
|
|
|
Consent of Akin Gump Strauss Hauer & Feld LLP
(contained in Exhibit 8.1)
|
|
24
|
.1
|
|
|
|
Powers of Attorney (included on the signature page to this
registration statement)
|
|
99
|
.1
|
|
|
|
Netherland, Sewell & Associates, Inc. Summary of
December 31, 2010 Reserves (included as Appendix C to
the prospectus)
|
|
99
|
.2
|
|
|
|
Netherland, Sewell & Associates, Inc. Summary Reserve
Report (included as Appendix D to the prospectus)
|
|
99
|
.3
|
|
|
|
Miller and Lents, Ltd. Summary of January 1, 2011 Reserves
(included as Appendix E to the prospectus)
|
|
|
|
* |
|
To be filed by amendment. |