As filed with
the Securities and Exchange Commission on December 29,
2010
Registration
No. 333-
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
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VOC Energy Trust
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VOC Brazos Energy Partners, L.P.
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(Exact Name of co-registrant as
specified in its charter)
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(Exact Name of co-registrant as
specified in its
charter)
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Delaware
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Texas
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(State or other jurisdiction of incorporation or
organization)
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(State or other jurisdiction of incorporation or
organization)
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1311
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1311
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(Primary Standard Industrial Classification Code Number)
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(Primary Standard Industrial Classification Code Number)
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80-6183103
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20-0079353
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(I.R.S. Employer Identification No.)
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(I.R.S. Employer Identification No.)
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919 Congress Avenue
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1700 Waterfront Parkway
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Suite 500
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Building 500
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Austin, Texas 78701
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Wichita, Kansas 67206
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(512) 236-6599
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(316) 682-1537
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(Address, including zip code, and telephone number,
including
area code, of co-registrants Principal Executive
Offices)
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(Address, including zip code, and telephone number,
including
area code, of co-registrants Principal Executive
Offices)
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The Bank of New York Mellon Trust
Company, N.A., Trustee
919 Congress Avenue
Suite 500
Austin, Texas 78701
(512) 236-6599
Attention: Michael J. Ulrich
(Name, address, including zip code, and telephone
number,
including area code, of agent for service)
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Barry Hill
1700 Waterfront Parkway
Building 500
Wichita, Kansas 67206
(316) 682-1537
(Name, address, including zip code, and telephone
number,
including area code, of agent for service)
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Copies to:
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David P. Oelman
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Joshua Davidson
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W. Matthew Strock
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Laura Tyson
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Vinson & Elkins L.L.P.
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Baker Botts L.L.P.
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1001 Fannin Street, Suite 2500
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910 Louisiana, Suite 3200
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Houston, Texas
77002-6760
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Houston, Texas 77002
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(713) 758-2222
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(713) 229-1234
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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,
please 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):
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Large
accelerated
filer o
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Accelerated
filer o
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Non-accelerated
filer þ
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Smaller reporting
company o
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(Do not check if a smaller
reporting company)
CALCULATION OF REGISTRATION FEE
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Proposed Maximum
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Amount of
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Title of Each Class of
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Aggregate Offering
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Registration
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Securities to be Registered
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Price (1)(2)
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Fee
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Units Of Beneficial Interest in VOC Energy Trust
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$200,000,000
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$23,220
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(1)
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Includes trust units issuable upon
exercise of the underwriters over-allotment option.
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(2)
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Estimated solely for the purpose of
calculating the registration fee pursuant to Rule 457(o).
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The co-registrants hereby amend this Registration Statement
on such date or dates as may be necessary to delay its effective
date until the co-registrants 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
these securities and it is not soliciting an offer to buy these
securities in any state where the offer or sale is not
permitted.
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Subject to Completion dated
December 29, 2010
PRELIMINARY PROSPECTUS
VOC Energy Trust
Trust Units
This is an initial public offering of units of beneficial
interest in VOC Energy Trust, or the trust. VOC
Sponsor (as defined in the Prospectus Summary) has
formed the trust and, immediately prior to the closing of this
offering, will convey, or cause to be conveyed, a term net
profits interest in oil and natural gas properties (the
Net Profits Interest) to the trust in exchange
for
trust units. VOC Sponsor is
offering
trust units to be sold in this offering and will receive all of
the proceeds derived therefrom. The underwriters have been
granted an option to purchase from VOC Sponsor up
to
additional trust units at the initial public offering price. VOC
Sponsor is a privately-held limited partnership engaged in the
production and development of oil and natural gas from
properties located in Kansas and Texas.
There is currently no public market for the trust units. VOC
Sponsor expects that the public offering price will be between
$ and
$ per trust unit. The trust
intends to apply to have the units approved for listing on the
New York Stock Exchange under the symbol VOC.
The trust units. Trust units are units of
beneficial interest in the trust and represent undivided
interests in the trust. They do not represent any interest in
VOC Sponsor.
The trust. The trust will own the Net Profits
Interest, which represents the right to receive during the term
of the trust 80% of the net proceeds from the sale of production
from oil and natural gas properties in Kansas and Texas, which
are referred to as the Underlying Properties, held
by VOC Sponsor as of the date of the conveyance of the Net
Profits Interest to the trust.
The trust unitholders. As a trust
unitholder, you will receive quarterly distributions of cash
from the proceeds that the trust receives from VOC Sponsor
pursuant to the Net Profits Interest.
Investing in the trust units involves a high degree of risk.
Before buying any trust units, you should read the discussion of
material risks of investing in the trust units in Risk
Factors beginning on page 22 of this prospectus.
Neither the Securities and Exchange Commission nor any state
securities commission has approved or disapproved of these
securities or passed upon the adequacy or accuracy of this
prospectus. Any representation to the contrary is a criminal
offense.
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Per
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Trust
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Unit
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Total
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Initial public offering price
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$
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$
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Underwriting discounts and commissions (1)
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$
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$
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Proceeds, before expenses, to VOC Sponsor
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$
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$
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(1)
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Excludes a structuring fee of 0.50%
of gross proceeds of the offering, or
$ ,
payable to Raymond James & Associates, Inc. by VOC
Sponsor for the evaluation, analysis and structuring of the
trust.
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The underwriters are offering the trust units as set forth
under Underwriting. Delivery of the trust units will
be made on or
about ,
2011.
RAYMOND JAMES
The date of this prospectus
is ,
2011
Geographic
Location of the Operating Areas
of the Underlying Properties in the States of Kansas and
Texas
TABLE OF
CONTENTS
Important
Notice About Information in This Prospectus
You should rely only on the information contained in this
prospectus or in any free writing prospectus we may authorize to
be delivered to you.
Until ,
2011 (25 days after the date of this prospectus), federal
securities laws may require all dealers that effect transactions
in the trust units, whether or not participating in this
offering, to deliver a prospectus. This is in addition to the
dealers obligation to deliver a prospectus when acting as
underwriters and with respect to their unsold allotments or
subscriptions.
VOC Sponsor and the trust have not, and the underwriters have
not, authorized anyone to provide you with additional or
different information. If anyone provides you with additional,
different or inconsistent information, you should not rely on
it. This prospectus is not an offer to sell or a solicitation of
an offer to buy the trust units in any jurisdiction where such
offer and sale would be unlawful. You should not assume that the
information contained in this prospectus is accurate as of any
date other than the date on the front of this document. The
trusts business, financial condition, results of
operations and prospects may have changed since such date.
i
PROSPECTUS
SUMMARY
This summary highlights information contained elsewhere in
this prospectus. To understand this offering fully, you should
read the entire prospectus carefully, including the risk factors
and the financial statements and notes to those statements.
Unless otherwise indicated, all information in this prospectus
assumes (a) an initial public offering price of
$ per trust unit and (b) no
exercise of the underwriters option to purchase additional
trust units.
Unless the context otherwise requires, as used in this
prospectus, (i) VOC Brazos refers to VOC Brazos
Energy Partners, L.P. without giving pro forma effect to the KEP
Acquisition (as defined below), (ii) KEP refers
to VOC Kansas Energy Partners, LLC, (iii) the Common
Control Properties include certain of the Underlying
Properties (as defined below) held by KEP that are deemed to be
under common control with VOC Brazos, (iv) the
Acquired Underlying Properties include the
Underlying Properties held by KEP that are not under common
control with VOC Brazos, (v) Predecessor refers
to VOC Brazos and the Common Control Properties on a combined
basis, as described in Selected historical and unaudited
pro forma financial, operating and reserve data of VOC
Sponsor, (vi) when discussing the assets, operations
or financial condition and results of operations of VOC Sponsor,
unless otherwise indicated, VOC Sponsor refers to
VOC Brazos and the Common Control Properties after giving effect
to the acquisition of the Acquired Underlying Properties, and
when discussing oil and natural gas reserve information of VOC
Sponsor, refers to the combined amounts of estimated proved oil
and natural gas reserves for VOC Brazos and KEP as reflected in
the reserve reports (as defined below), (vii) when
discussing the financial condition and results of operations
relating to the Underlying Properties, Underlying
Properties refers to the underlying oil and natural gas
properties attributable to Predecessor after giving pro forma
effect to the acquisition of the Acquired Underlying Properties
and after deducting all royalties and other burdens on
production thereon as of the date of the conveyance of the Net
Profits Interest to the trust, and (viii) the KEP
Acquisition refers to the acquisition by VOC Brazos of all
of the membership interests in KEP in exchange for limited
partner interests in VOC Brazos, resulting in KEP becoming a
wholly-owned subsidiary of VOC Brazos. For more information on
the KEP Acquisition and the acquisition of the Acquired
Underlying Properties by Predecessor, please see
Formation transactions and
Information about VOC Brazos Energy Partners, L.P. (VOC
Sponsor) General, respectively.
Cawley, Gillespie & Associates, Inc., an
independent engineering firm, provided the estimates of proved
oil and natural gas reserves for the underlying properties of
each of VOC Brazos and KEP as of December 31, 2009,
included in this prospectus. These estimates are contained in
summaries prepared by Cawley, Gillespie & Associates,
Inc. of its reserve reports as of December 31, 2009, for
the Underlying Properties. These summaries are located at the
back of this prospectus in Annex A and are collectively
referred to in this prospectus as the reserve
reports. You will find definitions for terms relating to
the oil and natural gas business in Glossary of Certain
Oil and Natural Gas Terms.
VOC
ENERGY TRUST
VOC Energy Trust is a Delaware statutory trust formed in
November 2010 by VOC Sponsor to own a term net profits interest
representing the right to receive 80% of the net proceeds
(calculated as described below) from production from
substantially all of the interests in oil and natural gas
properties in the states of Kansas and Texas held by VOC Sponsor
as of the date of the conveyance of the net profits interest to
the trust. We refer to the conveyed interest as the Net
Profits Interest. The Net Profits Interest will terminate
on the later to occur of (1) December 31, 2030, or
(2) the time when 9.7 MMBoe (which is the equivalent
of 7.8 MMBoe in respect of the Net Profits Interest) have
been produced from the Underlying Properties and sold.
1
As of December 31, 2009, the Underlying Properties produced
predominantly oil from approximately 892 gross (550.2 net)
wells located in 193 fields and had a projected reserve life in
excess of 50 years. Substantially all of the Underlying
Properties are located in mature oil fields that are
characterized by long production histories and several
additional development opportunities, which may help to diminish
natural declines in production from the Underlying Properties.
As of December 31, 2009, the total proved reserves
attributable to the Underlying Properties were 13.0 MMBoe,
of which approximately 84% were classified as proved developed
producing reserves, and approximately 92% were oil and
approximately 8% were natural gas. Based on the reserve reports,
the Net Profits Interest would entitle the trust to receive net
proceeds from the sale of production of 7.8 MMBoe of proved
reserves during the term of the trust, calculated as 80% of the
proved reserves attributable to the Underlying Properties
expected to be produced during the term of the trust. Average
net production from the Underlying Properties for the nine
months ended September 30, 2010 was approximately 2,583 Boe
per day (or 2,066 Boe per day attributable to the trust),
comprised of approximately 88% oil and approximately 12% natural
gas.
As of December 31, 2009, approximately 98% of the total
proved reserves relating to the Underlying Properties, based on
pre-tax present value of estimated future net revenue using a
discount rate of ten percent per annum
(PV-10),
were operated, or operated on a contract operator basis, by Vess
Oil Corporation (which we refer to as Vess Oil), L.
D. Drilling Inc. or Davis Petroleum, Inc. (which we refer to
collectively with Vess Oil as the VOC Operators).
See Planned development and workover
program for a summary of VOC Sponsors development
plans.
VOC Sponsor has entered into swap contracts for 2011, which we
refer to as the hedge contracts, at a strike price
of $94.90 per barrel of oil that hedge approximately 22% of
expected production during 2011 from the proved developed
producing reserves attributable to the Underlying Properties in
the summary reserve reports. The hedge contracts should help
mitigate the impact of any crude oil price volatility on
distributions made on the trust units with respect to the year
ending December 31, 2011. After these contracts expire at
various times in 2011, unitholder exposure to fluctuations in
crude oil prices will increase significantly.
The trust will make quarterly cash distributions of
substantially all of its quarterly cash receipts, after
deduction of fees and expenses for the administration of the
trust (which are estimated to be approximately $900,000 in
2011), to holders of its trust units during the term of the
trust. The first quarterly distribution is expected to be made
on or about August 15, 2011, to trust unitholders owning
trust units on or about August 1, 2011. The trusts
first quarterly distribution will consist of an amount in cash
paid by VOC Sponsor equal to the amount that would have been
payable to the trust had the Net Profits Interest been in effect
during the period from January 1, 2011 through
June 30, 2011, less any general and administrative expenses
and reserves of the trust. As a result of the extended period of
time that will be included in the first quarterly distribution,
subsequent quarterly distributions are likely to be less than
the initial distribution. Because payments to the trust will be
generated by depleting assets and the trust has a finite life
with the production from the Underlying Properties diminishing
over time, a portion of each distribution will represent, in
effect, a return of your original investment.
The trust will receive quarterly cash receipts from the net
proceeds attributable to the Net Profits Interest, with such net
proceeds being equal to 80% of:
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the gross proceeds received from sales of oil and natural gas
attributable to the Underlying Properties for each calendar
quarter; less
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the sum of the following:
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all lease operating expenses, production and property taxes, and
development expenses (including the cost of workovers and
recompletions, drilling costs and development costs, but subject
to certain limitations near the end of the term of the trust, as
described below in Computation of net proceeds
Net profits interest), paid by VOC Sponsor (collectively,
production and development costs); plus
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amounts that may be reserved for future development expenditures
(which reserve amounts may not exceed $1.0 million in the
aggregate at any given time); plus
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amounts paid to counterparties under hedge contracts; less
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amounts received from counterparties under hedge contracts.
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Net proceeds payable to the trust will depend upon, among other
things, volumes produced, wellhead prices, price differentials
and production and development costs. If for any quarter the
costs (after giving effect to any reduction for hedge proceeds
receipts) exceed gross proceeds, neither the trust nor the trust
unitholders would be liable for the excess costs; however, the
trust would not receive any net proceeds pursuant to the Net
Profits Interest until future gross proceeds for a quarter are
sufficient to repay those excess costs, plus interest at the
prime rate, as well as the applicable costs of such quarter. For
the nine months ended September 30, 2010, lease operating
expenses were $14.07 per Boe and production and property
taxes were $4.07 per Boe, for an aggregate production cost for
the Underlying Properties of $18.14 per Boe. As
substantially all of the Underlying Properties are located in
mature fields, VOC Sponsor does not expect its total future
production costs for the Underlying Properties to change
significantly as compared to recent historical costs other than
changes in costs due to any increases in the cost of general
oilfield services in its operating areas.
The amount of cash available for distribution by the trust will
be reduced by the general and administrative costs of the trust.
The business and affairs of the trust will be managed by The
Bank of New York Mellon Trust Company, N.A. as trustee, and
VOC Sponsor and its affiliates will have no ability to manage or
influence the operations of the trust.
FORMATION
TRANSACTIONS
At or prior to the closing of this offering, the following
transactions, which are referred to herein as the
formation transactions, will occur:
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VOC Brazos will acquire all of the membership interests in KEP
in exchange for newly issued limited partner interests in VOC
Brazos pursuant to a Contribution and Exchange Agreement dated
August 30, 2010, resulting in KEP becoming a wholly-owned
subsidiary of VOC Brazos. KEP was formed in November 2009 to
engage in the production and development of oil and natural gas
primarily within the state of Kansas. KEPs properties
consist of oil and gas properties that have been acquired or
developed by KEPs members since 1979. KEPs members
contributed these properties to KEP in December 2010. The
closing of the KEP Acquisition is conditioned solely upon the
closing of this offering.
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VOC Sponsor will convey to the trust the Net Profits Interest
effective as of January 1, 2011 in exchange
for
trust units in the aggregate, representing all of the
outstanding trust units of the trust.
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VOC Sponsor will sell
the
trust units offered hereby, representing a 65.2% interest in the
trust. VOC Sponsor will also make available during the
30-day
option period up
to
trust units for the underwriters to purchase at the initial
offering
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price to cover over-allotments. VOC Sponsor intends to use the
proceeds of the offering as disclosed under Use of
Proceeds.
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No more than forty-five days after the closing of this offering,
VOC Sponsor will sell the remaining trust units which it holds
to VOC Partners, LLC, an affiliate of VOC Sponsor, at the
initial offering price.
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VOC Sponsor and the trust will enter into an administrative
services agreement which will define the services VOC Sponsor
will provide to the trust on an ongoing basis as well as its
compensation therefor. Please see The trust.
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STRUCTURE
OF THE TRUST
The following chart shows the relationship of VOC Sponsor, VOC
Partners, LLC, the trust and the public trust unitholders after
the closing of this offering.
THE
UNDERLYING PROPERTIES
The Underlying Properties consist of VOC Sponsors net
interests in substantially all of its oil and natural gas
properties after deduction of all royalties and other burdens on
production thereon as of the date of conveyance of the Net
Profits Interest to the trust. As of December 31, 2009,
these oil and natural gas properties consisted of approximately
892 gross (550.2 net) producing oil and natural gas wells
in 193 fields in VOC Sponsors two operating areas, Kansas
and Texas. During the nine months ended September 30, 2010,
average net production from the Underlying Properties was
approximately 2,583 Boe per day (or 2,066 Boe per day
attributable to the trust) comprised of approximately 88% oil
and approximately 12% natural gas. VOC Sponsors interests
in the properties comprising the Underlying Properties require
VOC Sponsor to bear its proportionate share, along with the
other working interest owners, of the costs of development and
operation of such properties. As of December 31, 2009, VOC
Sponsor held average working interests of 74.7% and 66.8% in the
Underlying Properties located in the states of Kansas and Texas,
respectively. As of December 31, 2009, the VOC Operators
were the operators or contract operators of approximately 98% of
the total proved reserves attributable to the Underlying
Properties, based on
PV-10 value
and VOC sponsor held an average net revenue interest of 62.5%
and 55.1% for the Underlying Properties located in Kansas and
Texas
4
respectively. As of December 31, 2009, proved reserves
attributable to the Underlying Properties, as estimated in the
reserve reports, were approximately 13.0 MMBoe with a
PV-10 value
of $178.7 million.
Based on the reserve reports, the Net Profits Interest would
entitle the trust to receive net proceeds from the sale of
production of approximately 7.8 MMBoe of proved reserves
over the term of the trust. The trust is entitled to receive 80%
of the net proceeds from the sale of production of oil and
natural gas attributable to the Underlying Properties that are
produced during the term of the trust, whereas total reserves as
reflected in the reserve reports and attributable to the
Underlying Properties include all reserves expected to be
economically produced during the economic life of the properties.
VOC Sponsor has agreed to use commercially reasonable efforts to
cause the operators of the Underlying Properties to operate
these properties as would a reasonably prudent operator acting
with respect to its own properties (without regard to the
existence of the Net Profits Interest). In addition, after
giving effect to the conveyance of the Net Profits Interest to
the trust, VOC Sponsors interest in the Underlying
Properties will entitle it to 20% of the net proceeds from the
sale of production of oil and natural gas attributable to the
Underlying Properties during the term of the trust, and 100%
thereafter. VOC Sponsor believes that its retained interests in
the Underlying Properties combined with VOC Partners, LLCs
ownership of trust units representing a 34.8% beneficial
interest in the trust, which collectively entitle VOC Sponsor
and VOC Partners, LLC to receive an aggregate of approximately
48% of the net proceeds from the Underlying Properties, will
provide sufficient incentive to operate and develop the oil and
natural gas properties comprising the Underlying Properties in
an efficient and cost-effective manner.
OPERATING
AREAS
The Underlying Properties are located in Kansas and Texas in
areas characterized by long production histories and several
additional development opportunities, which may help to diminish
natural declines in production from the Underlying Properties.
See Planned development and workover
program for a summary of VOC Sponsors development
plans in each of the operating areas of the Underlying
Properties. Based on the reserve reports, approximately 92% of
the future production from the Underlying Properties is expected
to be oil, and approximately 8% is expected to be natural gas.
The following table summarizes, by state, the number of gross
producing wells, the estimated proved reserves attributable to
the Underlying Properties, the corresponding
PV-10 value
as of December 31, 2009, the average working interest,
average net revenue interest and the average daily net
production attributable to the Underlying Properties for the
nine-month period ended September 30, 2010, in each case
derived from the reserve reports. The reserve reports were
prepared by Cawley, Gillespie & Associates, Inc. in
accordance with criteria established by the
5
Securities and Exchange Commission (the SEC). The
summary reserve reports are included in Annex A to this
prospectus.
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Nine Month
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Period Ended
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Number
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September 30,
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of
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Proved Reserves (1)
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Average
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2010
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Gross
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Natural
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Average
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Net
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Average
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Producing
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Oil
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Gas
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Total
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% Oil
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% PDP
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PV-10
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Working
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|
|
Revenue
|
|
|
Net Production
|
|
Operating Area
|
|
Wells
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBoe) (2)
|
|
|
Reserves
|
|
|
Reserves
|
|
|
Value (3)
|
|
|
Interest
|
|
|
Interest
|
|
|
(Boe per day)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
|
|
|
Kansas
|
|
|
750
|
|
|
|
5,840
|
|
|
|
3,731
|
|
|
|
6,462
|
|
|
|
90.4
|
%
|
|
|
97.8
|
%
|
|
$
|
88.5
|
|
|
|
74.7
|
%
|
|
|
62.5
|
%
|
|
|
1,559
|
|
Texas
|
|
|
142
|
|
|
|
6,090
|
|
|
|
2,732
|
|
|
|
6,545
|
|
|
|
93.0
|
%
|
|
|
71.3
|
%
|
|
$
|
90.2
|
|
|
|
66.8
|
%
|
|
|
55.1
|
%
|
|
|
1,024
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
892
|
|
|
|
11,930
|
|
|
|
6,463
|
|
|
|
13,007
|
|
|
|
91.7
|
%
|
|
|
84.5
|
%
|
|
$
|
178.7
|
|
|
|
70.7
|
%
|
|
|
58.8
|
%
|
|
|
2,583
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
In accordance with the rules and
regulations promulgated by the SEC, the proved reserves
presented above were determined using the twelve month
unweighted arithmetic average of the
first-day-of-the-month
price for the period from January 1, 2009 through
December 1, 2009, without giving effect to any hedge
transactions, and were held constant for the life of the
properties. This yielded a price for oil of $61.18 per Bbl and a
price for natural gas of $3.83 per MMBtu.
|
|
(2)
|
|
Oil equivalents in the table are
the sum of the Bbls of oil and the Boe of the stated Mcfs of
natural gas, calculated on the basis that six Mcfs of natural
gas is the energy equivalent of one Bbl of oil.
|
|
(3)
|
|
PV-10
is the present value of estimated future net revenue to be
generated from the production of proved reserves, discounted
using an annual discount rate of 10%, calculated without
deducting future income taxes. Standardized measure of
discounted net cash flows is calculated the same as
PV-10 except
that it deducts future income taxes. Because VOC Sponsor bears
no federal income tax expense and taxable income is passed
through to the unitholders of the trust, no provision for
federal or state income taxes is included in the reserve reports
and therefore the standardized measure of discounted future net
cash flows attributable to the Underlying Properties is equal to
the pre-tax
PV-10 value.
PV-10 may not be considered a generally accepted accounting
principle (GAAP) financial measure as defined by the
SEC and is derived from the standardized measure of discounted
future net cash flows, which is the most directly comparable
GAAP financial measure. The pre-tax
PV-10 value
and the standardized measure of discounted future net cash flows
do not purport to present the fair value of the oil and natural
gas reserves attributable to Underlying Properties.
|
Kansas. As of December 31, 2009, proved reserves
attributable to the portion of the Underlying Properties located
in Kansas (the Kansas Underlying Properties) were
approximately 6.5 MMBoe and are located in three primary
areas the Central Kansas Uplift, Western Kansas and
South Central Kansas. As of December 31, 2009, the Kansas
Underlying Properties covered approximately 76,537 gross
acres (45,452.7 net acres) and included 190 fields. As
of December 31, 2009, the VOC Operators operated
approximately 96% of the total proved reserves attributable to
the Kansas Underlying Properties based on
PV-10 value.
The major fields in the Central Kansas Uplift include Fairport
Field, Chase-Silica Field and Marcotte Field, all of which are
producing primarily from the Arbuckle and Lansing Kansas City
zones. The major fields in Western Kansas include the Bindley,
Moore-Johnson and Wesley fields, which are producing primarily
from the Mississippian, Morrow, Lansing Kansas City and Cherokee
zones. The major fields in South Central Kansas include the
Gerberding, Spivey Grabs and Alford fields, which are producing
primarily from the Mississippian, Simpson and Lansing Kansas
City zones. During the nine-month period ended
September 30, 2010, the average net production for the
Kansas Underlying Properties was approximately 1,559 Boe per day.
Texas. As of December 31, 2009, proved reserves
attributable to the portion of the Underlying Properties located
in Texas (the Texas Underlying Properties) were
approximately 6.5 MMBoe and are located in two
areas Central Texas and East Texas. As of
December 31, 2009, the Texas Underlying Properties covered
approximately 23,693 gross acres (16,841.3 net acres)
and included
6
three fields. As of December 31, 2009, the VOC Operators
operated approximately 99% of the total proved reserves
attributable to the Texas Underlying Properties based on
PV-10 value.
Central Texas production is attributable to the Kurten Woodbine
Unit, which is producing primarily from the Woodbine Interval
and Buda Georgetown zones. East Texas properties include the
Sand Flat field and Hitts Lake North field, each of which is
producing primarily from the Paluxy and Chisum zones. During the
nine-month period ended September 30, 2010, the average net
production for the Texas Underlying Properties was approximately
1,024 Boe per day.
PLANNED
DEVELOPMENT AND WORKOVER PROGRAM
The primary goals of VOC Sponsors development and workover
program have been to develop proved undeveloped reserves, manage
workovers and minimize the natural decline in production. With
respect to the Underlying Properties, VOC Sponsor expects, but
is not obligated (subject to its reasonable discretion), to
implement the following development strategies specific to each
of its primary operating areas.
|
|
|
|
|
Kansas. VOC Sponsors historical development and
workover program for the Kansas Underlying Properties has
included recompleting certain existing wells, drilling infill
development wells, conducting
3-D seismic
surveys, completing workovers and applying new production
technologies. VOC Sponsor intends to continue this program with
respect to the Kansas Underlying Properties, and expects to
incur total development expenditures for these properties during
the next five years of approximately $0.5 million, most of
which is expected to be incurred during 2010 by the planned
drilling of two vertical development wells.
|
|
|
|
Texas. VOC Sponsors historical development and
workover program for the Texas Underlying Properties has
included recompleting certain existing wells, drilling infill
development wells, completing workovers and applying new
production technologies. In 2009, after an extensive review of
horizontal development drilling in the area, VOC Sponsor
commenced drilling horizontal wells in the Kurten Woodbine Unit
in order to accelerate the development of proved undeveloped
reserves. VOC Sponsor has successfully completed each of its
first four horizontal wells to the Woodbine C sand in this area
with average lateral lengths of approximately 3,000 feet.
VOC Sponsor intends to continue developing the Woodbine C sand
underlying the Kurten Woodbine Unit, utilizing horizontal wells
completed with multiple fracture stimulations together with
recompletions of existing vertical wellbores into additional pay
intervals. VOC Sponsor expects total development expenditures
for the Texas Underlying Properties during the next five years
to be approximately $24.8 million. Of this total, VOC
Sponsor contemplates spending approximately $21.5 million
to drill and complete 11 horizontal wells in the Woodbine C sand
and one vertical well in the Sand Flat Unit. The remaining
approximate $3.3 million is expected to be used for
recompletions and workovers of 13 Woodbine vertical wells to
additional Woodbine sands and six existing wells in the Sand
Flat Unit.
|
The trust is not directly obligated to pay any portion of any
development expenditures made with respect to the Underlying
Properties; however, development expenditures made by VOC
Sponsor with respect to the Underlying Properties will be
included among the costs that will be deducted from the gross
proceeds in calculating cash distributions attributable to Net
Profits Interest. As a result, the trust will indirectly bear an
80% share of any development expenditures made with respect to
the Underlying Properties (subject to certain limitations near
the end of the term of the trust, as described below).
Accordingly, higher or lower development expenditures will, in
general, directly decrease or increase, respectively, the cash
received by the trust. In making development expenditure
determinations, VOC Sponsor will attempt to balance the
7
impact of the development expenditures on current cash
distributions to the trust unitholders with the longer term
benefits of increased oil and natural gas production expected to
result from the development expenditure. In addition, VOC
Sponsor may establish a capital reserve of up to a maximum of
$1.0 million in the aggregate at any given time.
VOC Sponsor, as the designated operator of the Underlying
Properties, is entitled to make all determinations related to
development expenditures with respect to the Underlying
Properties, and there are no limitations on the amount of
development expenditures that VOC Sponsor may incur with respect
to the Underlying Properties, except as described below. VOC
Sponsor is required under the applicable Net Profits Interest
conveyance to use commercially reasonable efforts to cause the
operators of the Underlying Properties to operate these
properties as would a reasonably prudent operator, acting with
respect to its own properties (without regard to the existence
of the Net Profits Interest). As the trust unitholders would not
be expected to fully realize the benefits of development
expenditures made with respect to the Underlying Properties
which occur near the end of the term of the trust, during each
twelve-month period beginning on the later to occur of
(1) December 31, 2027 and (2) the time when
9.0 MMBoe have been produced from the Underlying Properties
and sold (which is the equivalent of 7.2 MMBoe in respect
of the Net Profits Interest), development expenditures that will
be taken into account in calculating net proceeds attributable
to the Net Profits Interest, will be limited to the average
annual development expenditures incurred by VOC Sponsor with
regard to the Underlying Properties during the preceding three
years, as adjusted for inflation. See Computation of net
proceeds Net profits interest.
VOC
SPONSOR
VOC Brazos is a privately-held limited partnership engaged in
the production and development of oil and natural gas from
properties located in Texas. VOC Brazos was formed in May 2003.
Pursuant to the KEP Acquisition, VOC Brazos will acquire KEP,
which was formed in November 2009 to develop and produce oil and
natural gas from properties primarily located in Kansas along
with a limited number of Texas properties. There are no
conditions to the closing of the KEP Acquisition other than the
closing of this offering. Members of KEP acquired interests in
the properties owned by KEP through various acquisitions and
drilling activities that have occurred since 1979. See
Formation transactions for a more
detailed discussion of the KEP Acquisition.
As of December 31, 2009, VOC Sponsor held interests in
approximately 892 gross (550.2 net) producing wells,
and proved reserves of the Underlying Properties were
approximately 13.0 MMBoe. As of December 31, 2009,
based on
PV-10 value,
the VOC Operators were the operators or contract operators of
approximately 98% of the total proved reserves attributable to
the Underlying Properties, with Vess Oil operating approximately
90% of the total proved reserves and L.D. Drilling Inc. and
Davis Petroleum, Inc. operating approximately 8% of the total
proved reserves. Vess Oil has operated oil and natural gas
properties in Kansas for more than 30 years and, according
to statistics furnished by the Kansas Geological Survey, was the
third largest operator of oil properties in Kansas measured by
production during 2009. Vess Oil currently operates over 1,600
oil, natural gas and service wells located primarily in Kansas,
with growing operations in Texas. As of September 30, 2010,
Vess Oil employed 19 full-time employees, three contract
professionals and 14 contract personnel in its Wichita office
and in five field and satellite offices.
For the year ended December 31, 2009, VOC Sponsor had
revenues and net earnings of $44.1 million and
$17.2 million, respectively. For the nine months ended
September 30, 2010, VOC Sponsor had pro forma revenues and
net income of $47.0 million and $25.5 million,
respectively. As of September 30, 2010, VOC Sponsor had pro
forma total assets of $173.3 million
8
and total liabilities of $33.4 million, including
indebtedness outstanding of $24.3 million. After giving
further pro forma effect to the conveyance of the Net Profits
Interest to the trust, the offering of the trust units
contemplated by this prospectus and the application of the net
proceeds as described in Use of proceeds, as of
September 30, 2010, VOC Sponsor would have had total assets
of $85.2 million and total liabilities of
$114.8 million, including indebtedness outstanding of
$24.3 million. For an explanation of the pro forma
adjustments, please read Financial statements of
Predecessor Unaudited pro forma statement of
earnings.
The address of VOC Sponsor is 1700 Waterfront Parkway, Building
500, Wichita, Kansas 67206, and its telephone number is
(316) 682-1537.
KEY
INVESTMENT CONSIDERATIONS
The following are some key investment considerations related to
the Underlying Properties, the Net Profits Interest and the
trust units:
|
|
|
|
|
Long-lived oil-producing properties. Oil-producing
properties in VOC Sponsors areas of operation have
historically had stable production profiles and generally
long-lived production, often with total economic lives in excess
of 50 years. VOC Sponsor acquired interests in the Texas
Underlying Properties through various acquisitions that have
occurred since the inception of VOC Brazos in 2003 and in the
Kansas Underlying Properties through the contribution to KEP by
its members in December 2010 of properties obtained through
various acquisitions and drilling activities since 1979. Proved
reserves attributable to the Underlying Properties have remained
relatively stable, ranging from approximately 13.2 MMBoe as
of December 31, 2007, to approximately 13.0 MMBoe as
of December 31, 2009. Based on the reserve reports and
assuming for purposes of this calculation that no additional
development drilling or other development expenditures are made
on the Underlying Properties after 2014, production from the
Underlying Properties is expected to decline at an average
annual rate of approximately 6.7% over the next 20 years.
VOC Sponsor may continue to drill beyond 2014, and such drilling
may reduce the anticipated decline rate if successful.
|
|
|
|
Substantial proved developed producing reserves. Proved
developed producing reserves are the lowest risk category of
reserves because production has already commenced, and VOC
Sponsor does not expect the proved developed producing reserves
attributable to the Underlying Properties to require significant
future development costs. Proved developed producing reserves
attributable to the Underlying Properties represented
approximately 84% of the
PV-10 value
of the Underlying Properties as of December 31, 2009.
|
|
|
|
Near term development activities. VOC Sponsor has
identified multiple locations on the Underlying Properties on
which it intends to drill new infill wells and recomplete
existing wells into new horizons over the next several years.
See Planned development and workover
program for a summary of VOC Sponsors development
plans. These locations are currently classified as proved
undeveloped reserves on the reserve reports. If these wells are
successfully completed or recompleted, as the case may be, the
additional production from these wells would partially offset
the natural decline in production from the Underlying
Properties. Any additional incremental revenue received by VOC
Sponsor from this additional production could have the effect of
increasing future distributions to the trust unitholders.
|
|
|
|
Operational control. The right to operate an oil and
natural gas lease is important because the operator can control
the timing and amount of discretionary expenditures for
|
9
|
|
|
|
|
operational and development activities. As of December 31,
2009, VOC Operators operated, or operated on a contract basis,
approximately 98% of the proved reserves attributable to the
Underlying Properties based on
PV-10 value.
|
|
|
|
|
|
Experienced Royalty Trust Sponsor. Certain members
of VOC Sponsors management team were involved in the
formation and initial public offering of MV Oil Trust (NYSE:
MVO) (MVO) a publicly-traded trust that is similar
to VOC Energy Trust. In connection with the formation of MVO,
the sponsor conveyed an 80% term net profits interest in oil and
natural gas properties in the Mid-Continent region in Kansas and
Colorado to MVO in exchange for trust units, a portion of which
were sold by the sponsor in MVOs initial public offering
in January 2007. The terms of the net profits interest being
conveyed in connection with the formation of VOC Energy Trust
are similar to those of the net profits interest which was
conveyed to MVO. To offset the natural decline in production of
the proved developed wells, the sponsor planned and executed a
development and workover program. The results of this program
have partially mitigated the decline, with average net
production being approximately 2,859 Boe per day (or
approximately 2,287 Boe per day attributable to MVOs 80%
net profit interest) at the time of the initial public offering
and 2,650 Boe per day (or approximately 2,120 Boe per day
attributable to MVOs 80% net profit interest) for the nine
months ended September 30, 2010. As a result of differences
in pricing, well locations, costs, development schedule,
development expenditures and regulatory environment, among other
things, the historical results of operations and performance of
MVO should not be relied on as an indicator of how the trust
will perform.
|
|
|
|
Strong oil fundamentals. Substantially all of the
production from the Underlying Properties consists of crude oil.
According to the US Energy Information Administration
(EIA) projections, world oil prices are expected to
rise gradually. These projections assume that global economic
growth results in higher global oil demand, growth in supply
from countries who are not members of the Organization of the
Petroleum Exporting Countries (OPEC) slows in 2011,
and members of OPEC continue to support world oil prices and
while commercial oil inventories in the Organization for
Economic Cooperation and Development (OECD)
countries begin to decline.
|
|
|
|
Downside oil price protection. VOC Sponsor has entered
into swap contracts for 2011 with a strike price of $94.90 per
barrel of oil that hedge approximately 22% of expected oil
production during 2011 from the proved developed producing
reserves attributable to the Underlying Properties. These hedge
contracts should help mitigate the impact of crude oil price
volatility on distributions made with respect to the trust units
during 2011. After these contracts expire at various times in
2011, unitholders exposure to fluctuations in commodity
prices, particularly fluctuations in crude oil prices, will
increase significantly. Under the terms of the conveyance, VOC
Sponsor will be prohibited from entering into hedging
arrangements for the benefit of the trust and the trustee is not
empowered to enter into hedge contracts with trust proceeds. For
more information on VOC Sponsors hedge positions, please
see The Underlying Properties Hedge
contracts.
|
|
|
|
Aligned interests of sponsor. Following the closing of
this offering, VOC Sponsor, together with VOC Partners, LLC,
will be entitled to receive an aggregate of approximately 48% of
the net proceeds attributable to the sale of oil and natural gas
produced from the Underlying Properties. This 48% interest will
consist of (1) the 20% of the net proceeds from the sale of
production of oil and natural gas and attributable to the
Underlying Properties that is retained by VOC Sponsor after
transferring to the trust the Net Profits
|
10
|
|
|
|
|
Interest and (2) the ownership by VOC Partners, LLC of
approximately 35% of the trust units following the closing of
this offering.
|
RISK
FACTORS
An investment in the trust units involves risks, including those
associated with fluctuations in energy commodity prices, the
operation of the Underlying Properties, the development of
proved reserves, the depleting nature of the Underlying
Properties, certain regulatory and legal matters, the structure
of the trust and the tax characteristics of the trust units.
Please read carefully the risks described under Risk
Factors on page 22 of this prospectus.
SUMMARY
PROVED RESERVES
Summary proved reserves of Underlying Properties and Net
Profits Interest. As of December 31, 2009, estimated
proved reserves attributable to the Underlying Properties were
approximately 92% oil and approximately 8% natural gas, based on
the reserve reports. The following table sets forth, as of
December 31, 2009, certain estimated proved oil and natural
gas reserves, estimated future net revenues and the discounted
present value thereof attributable to the Underlying Properties
and the Net Profits Interest, in each case as derived from the
reserve reports.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserves of the Underlying Properties
|
|
Undiscounted
|
|
|
|
|
Oil
|
|
Natural Gas
|
|
Oil Equivalent
|
|
Future Net
|
|
PV-10
|
|
|
(MBbls )
|
|
(MMcf)
|
|
(MBoe)
|
|
Revenues
|
|
Value
|
|
|
|
|
|
|
|
|
(In thousands)
|
|
Underlying Properties (total) (1)
|
|
|
11,930
|
|
|
|
6,463
|
|
|
|
13,007
|
|
|
$
|
371,468
|
|
|
$
|
178,690
|
|
Underlying Properties (attributable to the Net Profits Interest)
(2)
|
|
|
7,132
|
|
|
|
4,003
|
|
|
|
7,799
|
|
|
$
|
238,175
|
|
|
|
|
|
|
|
|
(1)
|
|
Reflects 100% of the proved
reserves attributable to the Underlying Properties.
|
|
(2)
|
|
Reflects 80% of proved reserves
attributable to the Underlying Properties expected to be
produced during the term of the trust.
|
11
Annual production attributable to Net Profits Interest.
The following graph shows estimated monthly production of total
proved reserves attributable to the Net Profits Interest based
upon the pricing and other assumptions set forth in the reserve
reports. This graph presents the total proved reserves as
reflected in the reserve reports broken down by three reserve
categories (proved developed producing, proved developed
non-producing and proved undeveloped reserves) which demonstrate
the impact of developmental drilling and well re-completion and
workover activities that VOC Sponsor expects to undertake with
respect to the Underlying Properties within the next five years.
For a description of VOC Sponsors planned development,
workover and recompletion programs over the next five years, see
The Underlying Properties Planned development
and workover program.
Estimated
Annual Production of Proved Reserves
Attributable to the Net Profits Interest
12
SUMMARY
UNAUDITED PRO FORMA COMBINED FINANCIAL DATA AND OPERATING DATA
FOR THE UNDERLYING PROPERTIES OF VOC SPONSOR AND THE
TRUST
Pro Forma
Combined Financial Data of the Underlying Properties
The summary unaudited pro forma combined financial data
presented below should be read in conjunction with The
Underlying Properties Selected historical and
unaudited pro forma financial and operating data of the
Underlying Properties and the accompanying financial
statements and related notes included elsewhere in this
prospectus. The following table sets forth revenues, direct
operating expenses and the excess of revenues over direct
operating expenses relating to the Predecessor Underlying
Properties after giving pro forma effect to the acquisition of
the Acquired Underlying Properties. The summary unaudited pro
forma financial data for the year ended December 31, 2009
and for the nine months ended September 30, 2010 have been
derived from the unaudited pro forma statements of historical
revenues and direct operating expenses of the Underlying
Properties included in this prospectus beginning on
page F-18.
The pro forma adjustments have been prepared as if the
acquisition of the Acquired Underlying Properties by Predecessor
had taken place as of January 1, 2009.
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Nine Months Ended
|
|
|
|
December 31, 2009
|
|
|
September 30, 2010
|
|
|
|
(In thousands)
|
|
|
|
(Unaudited)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
40,360
|
|
|
$
|
44,682
|
|
Natural gas sales
|
|
|
2,292
|
|
|
|
2,540
|
|
Hedge and other derivative activity
|
|
|
1,477
|
|
|
|
(151
|
)
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
44,129
|
|
|
|
47,071
|
|
|
|
|
|
|
|
|
|
|
Bad debt recovery
|
|
|
(719
|
)
|
|
|
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
12,757
|
|
|
|
9,919
|
|
Production and property taxes
|
|
|
2,816
|
|
|
|
2,869
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
15,573
|
|
|
|
12,788
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
29,275
|
|
|
$
|
34,283
|
|
|
|
|
|
|
|
|
|
|
13
Pro Forma
Distributable Income of the Trust
The table below outlines the calculation of distributable income
from Net Profits Interest derived from the excess of revenues
over direct operating expenses of the Underlying Properties for
the year ended December 31, 2009 and the nine months ended
September 30, 2010 and should be read in conjunction with
the unaudited pro forma financial information of the Trust
included in this prospectus beginning on
page F-24:
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Nine Months Ended
|
|
|
|
December 31, 2009
|
|
|
September 30, 2010
|
|
|
|
(In thousands, except per unit data)
|
|
|
|
(Unaudited)
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
29,275
|
|
|
$
|
34,283
|
|
Less development expenses
|
|
|
5,129
|
|
|
|
8,829
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses and
development expenses
|
|
|
24,146
|
|
|
|
25,454
|
|
Times Net Profits Interest over the term of the trust
|
|
|
80
|
%
|
|
|
80
|
%
|
|
|
|
|
|
|
|
|
|
Income from Net Profits Interest
|
|
|
19,316
|
|
|
|
20,363
|
|
|
|
|
|
|
|
|
|
|
Pro forma adjustments:
|
|
|
|
|
|
|
|
|
Less estimated trust general and administrative expenses
|
|
|
900
|
|
|
|
675
|
|
|
|
|
|
|
|
|
|
|
Distributable income
|
|
$
|
18,416
|
|
|
$
|
19,688
|
|
|
|
|
|
|
|
|
|
|
Distributable income per trust unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Data of the Underlying Properties
The following table provides oil and natural gas sales volumes,
average sales prices and capital expenditures relating to the
Underlying Properties for the years ended December 31,
2007, 2008 and 2009 and for the nine months ended
September 30, 2009 and 2010. Average sales prices do not
include the effect of hedge activity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended December 31,
|
|
|
September 30,
|
|
Underlying
Properties (1)
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
705
|
|
|
|
704
|
|
|
|
732
|
|
|
|
543
|
|
|
|
618
|
|
Natural gas (MMcf)
|
|
|
738
|
|
|
|
750
|
|
|
|
693
|
|
|
|
525
|
|
|
|
519
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales (MBoe)
|
|
|
828
|
|
|
|
829
|
|
|
|
847
|
|
|
|
631
|
|
|
|
705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
67.15
|
|
|
$
|
93.67
|
|
|
$
|
55.16
|
|
|
$
|
50.01
|
|
|
$
|
72.25
|
|
Natural gas (per Mcf)
|
|
$
|
5.96
|
|
|
$
|
7.46
|
|
|
$
|
3.31
|
|
|
$
|
3.10
|
|
|
$
|
4.89
|
|
Capital expenditures (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
$
|
4,463
|
|
|
$
|
7,899
|
|
|
$
|
4,134
|
|
|
$
|
1,981
|
|
|
$
|
2,884
|
|
Well development
|
|
|
2,420
|
|
|
|
2,499
|
|
|
|
2,407
|
|
|
|
1,027
|
|
|
|
6,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
6,883
|
|
|
$
|
10,398
|
|
|
$
|
6,541
|
|
|
$
|
3,008
|
|
|
$
|
8,983
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The operating data below includes
the effect of the Acquired Underlying Properties for all periods
presented.
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended December 31,
|
|
|
September 30,
|
|
Predecessor Underlying
Properties
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
387
|
|
|
|
389
|
|
|
|
407
|
|
|
|
298
|
|
|
|
374
|
|
Natural gas (MMcf)
|
|
|
391
|
|
|
|
426
|
|
|
|
415
|
|
|
|
311
|
|
|
|
339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
452
|
|
|
|
460
|
|
|
|
477
|
|
|
|
350
|
|
|
|
431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
67.31
|
|
|
$
|
94.11
|
|
|
$
|
55.86
|
|
|
$
|
50.37
|
|
|
$
|
73.15
|
|
Natural gas (per Mcf)
|
|
$
|
6.39
|
|
|
$
|
7.86
|
|
|
$
|
3.64
|
|
|
$
|
3.36
|
|
|
$
|
5.47
|
|
Capital expenditures (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
$
|
3,523
|
|
|
$
|
6,715
|
|
|
$
|
2,369
|
|
|
$
|
1,027
|
|
|
$
|
2,328
|
|
Well development
|
|
|
1,603
|
|
|
|
1,063
|
|
|
|
1,955
|
|
|
|
747
|
|
|
|
5,638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,126
|
|
|
$
|
7,778
|
|
|
$
|
4,324
|
|
|
$
|
1,774
|
|
|
$
|
7,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended December 31,
|
|
|
September 30,
|
|
Acquired Underlying
Properties
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
319
|
|
|
|
315
|
|
|
|
324
|
|
|
|
245
|
|
|
|
244
|
|
Natural gas (MMcf)
|
|
|
347
|
|
|
|
324
|
|
|
|
278
|
|
|
|
214
|
|
|
|
180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales (MBoe)
|
|
|
376
|
|
|
|
369
|
|
|
|
371
|
|
|
|
281
|
|
|
|
274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
66.96
|
|
|
$
|
93.12
|
|
|
$
|
54.27
|
|
|
$
|
49.58
|
|
|
$
|
70.85
|
|
Natural gas (per Mcf)
|
|
$
|
5.49
|
|
|
$
|
6.94
|
|
|
$
|
2.81
|
|
|
$
|
2.72
|
|
|
$
|
3.80
|
|
Capital expenditures (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
$
|
940
|
|
|
$
|
1,184
|
|
|
$
|
1,765
|
|
|
$
|
954
|
|
|
$
|
556
|
|
Well development
|
|
|
817
|
|
|
|
1,436
|
|
|
|
452
|
|
|
|
280
|
|
|
|
461
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,757
|
|
|
$
|
2,620
|
|
|
$
|
2,217
|
|
|
$
|
1,234
|
|
|
$
|
1,017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Historical
and Pro Forma Financial Data of VOC Sponsor
The summary historical audited financial data of Predecessor as
of and for the year ended December 31, 2009 has been
derived from the audited financial statements of Predecessor
beginning on page
VOC F-2.
The summary unaudited financial data of Predecessor as of and
for the nine months ended September 30, 2010 has been
derived from the unaudited financial statements of Predecessor
beginning on page
VOC F-2.
The summary unaudited pro forma financial data as of and for the
year ended December 31, 2009 and as of and for the nine
months ended September 30, 2010 set forth in the following
table have been derived from the unaudited pro forma financial
statements of Predecessor included in this prospectus beginning
on page VOC
F-27. The
pro forma adjustments have been prepared as if the acquisition
of the Acquired
15
Underlying Properties and, with respect to pro forma as adjusted
information, the conveyance of the Net Profits Interest, the
offer and sale of the trust units and application of the net
proceeds therefrom, had taken place (i) on
September 30, 2010, in the case of the pro forma balance
sheet information as of September 30, 2010, and
(ii) as of January 1, 2009, in the case of the pro
forma statement of earnings information for the year ended
December 31, 2009, and the nine months ended
September 30, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Pro Forma for the
|
|
Predecessor Pro Forma As
|
|
|
|
|
|
|
Acquisition of the Acquired
|
|
Adjusted for the Offering
|
|
|
Predecessor
|
|
Underlying Properties
|
|
(Including the conveyance of the Net Profits Interest)
|
|
|
|
|
Nine Months
|
|
|
|
Nine Months
|
|
|
|
Nine Months
|
|
|
Year Ended
|
|
Ended
|
|
Year Ended
|
|
Ended
|
|
Year Ended
|
|
Ended
|
|
|
December 31,
|
|
September 30,
|
|
December 31,
|
|
September 30,
|
|
December 31,
|
|
September 30,
|
|
|
2009
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
2010
|
|
|
(In thousands)
|
|
|
|
|
(Unaudited)
|
|
(Unaudited)
|
|
(Unaudited)
|
|
Revenue
|
|
$
|
25,750
|
|
|
$
|
29,091
|
|
|
$
|
44,133
|
|
|
$
|
47,073
|
|
|
$
|
15,836
|
|
|
$
|
14,633
|
|
Net earnings
|
|
$
|
10,861
|
|
|
$
|
16,557
|
|
|
$
|
17,222
|
|
|
$
|
25,510
|
|
|
$
|
9,230
|
|
|
$
|
9,269
|
|
Total assets (at period end)
|
|
$
|
101,280
|
|
|
$
|
109,626
|
|
|
|
|
|
|
$
|
173,271
|
|
|
|
|
|
|
$
|
85,220
|
|
Long-term liabilities, excluding current maturities (at period
end)
|
|
$
|
28,315
|
|
|
$
|
26,765
|
|
|
|
|
|
|
$
|
28,822
|
|
|
|
|
|
|
$
|
102,264
|
|
Partners capital/common control owners equity
(deficit)
|
|
$
|
67,512
|
|
|
$
|
79,932
|
|
|
|
|
|
|
$
|
139,876
|
|
|
|
|
|
|
$
|
(29,581
|
)
|
SUMMARY
PROJECTED CASH DISTRIBUTIONS
The following table presents a calculation of cash distributions
to holders of trust units as if they owned trust units as of the
record date for the distribution for the first quarter of 2011
(assuming, for purposes of the table, that there were quarterly
distributions made for each of the four quarters in
2011) and continued to own those trust units through the
record date for the cash distribution payable with respect to
oil and natural gas production for the last quarter of 2011. The
cash distribution projections for the twelve months ending
December 31, 2011 were prepared by VOC Sponsor on an
accrual of production basis based on the hypothetical
assumptions that are described below and in Projected cash
distributions Significant assumptions used to
prepare the projected cash distributions. By accrual of
production basis, it is assumed that cash distributions for a
quarter relate to actual production in that quarter as opposed
to cash received in that quarter. Actual cash distributions by
the trust will be made on a cash basis, however, and, as a
result, will vary from the projected cash distributions
presented in the table below due to, among other things, the
delay between accruing for sales of production and VOC
Sponsors receiving payment from purchasers of the
production. In addition, for the year ending December 31,
2011, VOC Sponsor will not make its first payment to the trust
pursuant to the Net Profits Interest until on or about
August 15, 2011. The trusts first quarterly
distribution will consist of an amount in cash paid by VOC
Sponsor equal to the amount that would have been payable to the
trust had the Net Profits Interest been in effect during the
period from January 1, 2011 through June 30, 2011,
less any general and administrative expenses and reserves of the
trust.
VOC Sponsor does not as a matter of course make public
projections as to future sales, earnings or other results.
However, the management of VOC Sponsor has prepared the
projected financial information set forth below to present the
projected cash distributions to the holders of the trust units
based on the estimates and hypothetical assumptions described
below. The accompanying projected financial information was not
prepared with a view toward complying with the published
guidelines of the SEC or guidelines established by the American
Institute of Certified Public Accountants with respect to
projected financial information.
In the view of VOC Sponsors management, the accompanying
unaudited projected financial information was prepared on a
reasonable basis and reflects the best currently available
estimates
16
and judgments of VOC Sponsor related to oil and natural gas
production, operating expenses, development expenditures, and
other general and administrative expenses based on:
|
|
|
|
|
the oil and natural gas production estimates for the year ending
December 31, 2011 contained in the reserve reports;
|
|
|
|
estimated production and development costs for the year ending
December 31, 2011, contained in the reserve reports;
|
|
|
|
projected payments made or received pursuant to the hedge
contracts for the year ending December 31, 2011; and
|
|
|
|
further reduction in estimated general and administrative
expenses of $900,000 in 2011.
|
The projected financial information was also based on the
hypothetical assumption that prices for oil and natural gas
remain constant during the twelve months ending
December 31, 2011 and are $
per Bbl of oil and $ per MMBtu of
natural gas (which prices exclude the effects of financial
hedging arrangements). These prices represent average annual
NYMEX futures prices. These hypothetical prices are then
adjusted to take into account VOC Sponsors estimate of the
basis differential (based on location and quality of the
production) between published prices and the prices actually
received by VOC Sponsor. Actual prices paid for oil and natural
gas expected to be produced from the Underlying Properties in
2011 will likely differ from these hypothetical prices due to
fluctuations in the prices generally experienced with respect to
the production of oil and natural gas and variations in basis
differentials. For example, the published average monthly
closing NYMEX crude oil spot price per Bbl was $78.10 for the
nine months ended September 30, 2010, while the actual
monthly closing prices ranged from $71.92 to $86.15 during such
period. See Risk factors Prices of oil and
natural gas fluctuate due to a number of factors that are beyond
the control of the trust and VOC Sponsor, and lower prices could
reduce proceeds to the trust and cash distributions to
unitholders.
VOC Sponsor utilized these production estimates, hypothetical
oil and natural gas prices and cost estimates in preparing the
projected financial information. This methodology is consistent
with the requirements of the SEC for estimating oil and natural
gas reserves and discounted present value of future net revenues
attributable to the Net Profits Interest, except that we have
utilized average annual NYMEX futures prices rather than average
historical monthly price for oil and natural gas. The actual
production amounts, commodity prices and costs for 2011 may vary
from those VOC Sponsor has projected, and such variations could
be material. Accordingly, the projected financial information
should not be relied upon as being necessarily indicative of
future results. Readers of this prospectus are cautioned not to
place undue reliance on the projected financial information.
Neither VOC Sponsors independent auditors nor any other
independent accountants have compiled, examined or performed any
procedures with respect to the projected financial information
contained herein, nor have they expressed any opinion or any
other form of assurance on such information or its
achievability, and assume no responsibility for, and disclaim
any association with, the projected financial information.
The projections and the estimates and hypothetical assumptions
on which they are based are subject to significant
uncertainties, many of which are beyond the control of VOC
Sponsor or the trust. Actual cash distributions to trust
unitholders, therefore, could vary significantly based upon
events or conditions occurring that are different from the
events or conditions assumed to occur for purposes of these
projections. Cash distributions to trust unitholders will be
particularly sensitive to fluctuations in oil and natural gas
prices. See Risk factors Prices of oil and
natural
17
gas fluctuate due to a number of factors that are beyond the
control of the trust and VOC Sponsor, and lower prices could
reduce proceeds to the trust and cash distributions to
unitholders. As a result of typical production declines
for oil and natural gas properties, production estimates
generally decrease from year to year, and the projected cash
distributions shown in the table below are not necessarily
indicative of distributions for future years. See
Projected cash distributions Sensitivity of
projected cash distributions to oil and natural gas production
and prices, which shows projected effects on cash
distributions from hypothetical changes in oil and natural gas
production and prices. Because payments to the trust will be
generated by depleting assets and the trust has a finite life
with the production from the Underlying Properties diminishing
over time, a portion of each distribution will represent, in
effect, a return of your original investment. See Risk
factors The reserves attributable to the Underlying
Properties are depleting assets and production from those
reserves will diminish over time. Furthermore, the trust is
precluded from acquiring other oil and natural gas properties or
net profits interests to replace the depleting assets and
production. Therefore, proceeds to the trust and cash
distributions may decrease over time.
18
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Projection for Twelve Months
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Projected Cash Distributions
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Ending December 31, 2011
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(Dollars in thousands, except
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per Bbl, Mcf, MMBtu and per unit
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amounts)
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Underlying Properties sales volumes:
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Oil (MBbls)
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Natural gas (MMcf)
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Total sales (MBoe)
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NYMEX futures price (1):
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Oil (per Bbl)
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$
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Natural gas (per MMBtu)
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$
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Assumed realized sales price (2):
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Oil (per Bbl)
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$
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Natural gas (per Mcf)
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$
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Calculation of net proceeds:
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Gross proceeds:
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Oil sales
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$
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Natural gas sales
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Total
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$
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Costs:
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Production and development costs:
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Lease operating expenses
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$
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Production and property taxes
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Development expenses
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Total
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$
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Settlement of hedge contracts (payment received) (3)
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Net proceeds
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$
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Percentage allocable to Net Profits Interest
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80
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%
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Net proceeds to trust from Net Profits Interest
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$
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Trust general and administrative expenses (4)
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Cash available for distribution by the trust
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$
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Cash distribution per trust unit
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$
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(1)
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Average NYMEX futures price for
2011, as reported
on .
For a description of the effect of lower NYMEX prices on
projected cash distributions, please read
Sensitivity of projected cash distributions to oil and natural
gas production and prices.
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(2)
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Sales price net of forecasted
gravity, quality, transportation, and marketing costs. For more
information about the estimates and hypothetical assumptions
made in preparing the table above, see Projected cash
distributions Significant assumptions used to
prepare the projected cash distributions.
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(3)
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Costs will be reduced by hedge
payments received by VOC Sponsor under the hedge contracts. If
the hedge payments received by VOC Sponsor under the hedge
contracts exceed costs during a quarterly period, the ability to
use such excess amounts to offset costs will be deferred, with
interest accruing on such amounts at the prevailing money market
rate, until the next quarterly period when the hedge payments
are less than such costs.
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(4)
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Total general and administrative
expenses of the trust on an annualized basis for 2011 are
expected to be $900,000, which includes an annual administrative
fee to VOC Sponsor in the amount of $75,000 in 2011, which fee
will increase by 4% annually beginning in January 2012, the
annual fee to the trustees, accounting fees, engineering fees,
printing costs and other expenses properly chargeable to the
trust.
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19
THE
OFFERING
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Trust units offered by VOC Sponsor |
|
trust
units
or, trust
units, if the underwriters exercise their option to purchase
additional trust units in full |
|
Trust units owned by VOC Partners, LLC after the offering |
|
trust
units, if the underwriters exercise their option to purchase
additional trust units in full |
|
Trust units outstanding after the offering |
|
trust
units |
|
Use of proceeds |
|
VOC Sponsor is offering all of the trust units to be sold in
this offering including, the trust units to be sold upon any
exercise of the underwriters over-allotment option. The
estimated net proceeds of this offering to be received by VOC
Sponsor will be approximately
$ million, after deducting
underwriting discounts and commissions, structuring fees and
expenses, and $ million if
the underwriters exercise their option to purchase additional
trust units in full. VOC Sponsor intends to use the net proceeds
from this offering, including any proceeds from the exercise of
the underwriters option to purchase additional trust units
and the sale of the trust units to VOC Partners, LLC to make
cash distributions to its limited partners. See Use of
proceeds. |
|
Proposed NYSE symbol |
|
VOC |
|
Quarterly cash distributions |
|
It is expected that quarterly cash distributions during the term
of the trust, other than the first quarterly cash distribution,
will be made by the trustee on or about the 45th day following
the end of each quarter to the trust unitholders of record on
the 30th day following the end of each quarter (or the next
succeeding business day). The first distribution from the trust
to the trust unitholders will be made on or about
August 15, 2011 to trust unitholders owning trust units on
or about August 1, 2011. The trusts first quarterly
distribution will consist of an amount in cash paid by VOC
Sponsor equal to the amount that would have been payable to the
trust had the Net Profits Interest been in effect during the
period from January 1, 2011 through June 30, 2011,
less any general and administrative expenses and reserves of the
trust. |
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|
Actual cash distributions to the trust unitholders will
fluctuate quarterly based upon the quantity of oil and natural
gas produced from the Underlying Properties, the prices received
for oil and natural gas production and other factors. Because
payments to the trust will be generated by depleting assets and
the trust has a finite life with the |
20
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production from the Underlying Properties diminishing over time,
a portion of each distribution will represent, in effect, a
return of your original investment. Oil and natural gas
production from proved reserves attributable to the Underlying
Properties is expected to decline over the term of the trust.
See Risk factors. |
|
Termination of the trust |
|
The Net Profits Interest will terminate on the later to occur of
(1) December 31, 2030, or (2) the time when
9.7 MMBoe have been produced from the Underlying Properties
and sold (which amount is the equivalent of 7.8 MMBoe in
respect of the trusts right to receive 80% of the net
proceeds from the Underlying Properties pursuant to the Net
Profits Interest), and the trust will promptly wind up its
affairs and terminate thereafter. |
|
Summary of income tax consequences |
|
Trust unitholders will be taxed directly on the income from
assets of the trust. The Net Profits Interest should be treated
as a debt instrument for federal income tax purposes, and a
trust unitholder in that event will be required to include in
such trust unitholders income its share of the interest
income on such debt instrument as it accrues in accordance with
the rules applicable to contingent payment debt instruments
contained in the Internal Revenue Code of 1986, as amended, and
the corresponding regulations. If the Net Profits Interest is
not treated as a debt instrument, then a trust unitholder should
be allowed to recoup its basis in the Net Profits Interest on a
schedule that is in proportion to production attributable to the
Net Profits Interest and that may be more favorable to a trust
unitholder than the schedule on which basis will be recovered if
the Net Profits Interest is treated as a debt instrument for
federal income tax purposes. See Federal income tax
consequences. |
21
RISK
FACTORS
Prices of oil and natural gas fluctuate due to a number of
factors that are beyond the control of the trust and VOC
Sponsor, and lower prices could reduce proceeds to the trust and
cash distributions to unitholders.
The trusts reserves and quarterly cash distributions are
highly dependent upon the prices realized from the sale of oil
and natural gas. Prices of oil and natural gas can fluctuate
widely on a
quarter-to-quarter
basis in response to a variety of factors that are beyond the
control of the trust and VOC Sponsor. These factors include,
among others:
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regional, domestic and foreign supply and perceptions of supply
of oil and natural gas;
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the level of demand and perceptions of demand for oil and
natural gas;
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political conditions or hostilities in oil and natural gas
producing regions;
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anticipated future prices of oil and natural gas and other
commodities;
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weather conditions and seasonal trends;
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technological advances affecting energy consumption and energy
supply;
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U.S. and worldwide economic conditions;
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the price and availability of alternative fuels;
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the proximity, capacity, cost and availability of gathering and
transportation facilities;
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the volatility and uncertainty of regional pricing differentials;
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governmental regulations and taxation;
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energy conservation and environmental measures; and
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acts of force majeure.
|
The slowdown in economic activity caused by the worldwide
economic recession has reduced worldwide demand for energy and
resulted in lower crude oil and natural gas prices. Crude oil
prices declined from record high levels in early July 2008 of
over $140 per Bbl to below $45 per Bbl in February 2009 before
rebounding to over $80 per Bbl in November 2010. Natural gas
prices declined from over $13 per MMBtu in mid-2008 to
approximately $4 per MMBtu in November 2010.
Lower prices of oil and natural gas will reduce proceeds to
which the trust is entitled and may ultimately reduce the amount
of oil and natural gas that is economic to produce from the
Underlying Properties. As a result, the operator of any of the
Underlying Properties could determine during periods of low
commodity prices to shut in or curtail production from wells on
the Underlying Properties. In addition, the operator of the
Underlying Properties could determine during periods of low
commodity prices to plug and abandon marginal wells that
otherwise may have been allowed to continue to produce for a
longer period under conditions of higher prices. Specifically,
VOC Sponsor may abandon any well or property if it reasonably
believes that the well or property can no longer produce oil or
natural gas in commercially economic quantities.
22
This could result in termination of the Net Profits Interest
relating to the abandoned well or property. In making such
decisions, VOC Sponsor and any transferee will be required under
the applicable conveyance to operate, or to use commercially
reasonable efforts to cause the operators of the Underlying
Properties to operate these properties as would a reasonably
prudent operator, acting with respect to its own properties
(without regard to the existence of the Net Profits Interest).
Because substantially all the Underlying Properties are located
in mature fields, decreases in commodity prices could have a
more significant effect on the economic viability of these
properties as compared to more recently discovered properties.
The commodity price sensitivity of these mature wells is due to
a variety of factors that vary from
well-to-well,
including the additional costs associated with water handling
and disposal, chemicals, surface equipment maintenance, downhole
casing repairs and reservoir pressure maintenance activities
that are necessary to maintain production. As a result, the
volatility of commodity prices may cause the amount of future
cash distributions to trust unitholders to fluctuate, and a
substantial decline in the price of oil or natural gas will
reduce the amount of cash available for distribution to the
trust unitholders. The volatility of commodity prices also
reduces the accuracy of estimates of future cash distributions
to trust unitholders.
VOC Sponsor has entered into hedge contracts relating to
approximately 22% of expected production from the proved
developed producing reserves attributable to the Underlying
Properties during 2011. These hedge contracts expire at various
dates in 2011. While the use of hedging transactions limits the
downside risk of price declines, they may also limit the
trusts ability to realize cash flow from crude oil price
increases on the portion of the production attributable to the
Net Profits Interest that is hedged during such period. The
trust will be required to bear its share of the hedge payments
regardless of whether the corresponding quantities of oil are
produced or sold. Furthermore, VOC Sponsor has not entered into
any hedge contracts relating to oil and natural gas volumes
expected to be produced after December 31, 2011, and the
terms of the conveyance of the Net Profits Interests will
prohibit VOC Sponsor from entering into new hedging arrangements
following the completion of this offering. As a result, the
amounts of the cash distributions may be subject to a greater
fluctuation after December 31, 2011 because of changes in
crude oil prices. In the event that any of the counterparties to
the hedge contracts default on their obligations to make
payments to VOC Sponsor under the hedge contracts, the cash
distributions to the trust unitholders would likely be
materially reduced. VOC Sponsor will have no continuing
obligation with respect to these swap contracts. For a
discussion of the hedge contracts, see The Underlying
Properties Hedge contracts.
An increase in the differential between the price realized
by VOC Sponsor for oil or natural gas produced from the
Underlying Properties and the NYMEX or other benchmark price of
oil or natural gas could reduce the proceeds to the trust and
therefore the cash distributions by the trust and the value of
trust units.
The prices received for VOC Sponsors oil and natural gas
production usually fall below the relevant benchmark prices,
such as NYMEX, that are used for calculating hedge positions.
The difference between the price received and the benchmark
price is called a basis differential. The differential may vary
significantly due to market conditions, the quality and location
of production and other factors. VOC Sponsor cannot accurately
predict natural gas or crude oil differentials. Increases in the
differential between the realized price of oil and natural gas
and the benchmark price for oil and natural gas could reduce the
proceeds to the trust and therefore the cash distributions by
the trust and the value of the trust units.
23
Estimates of future cash distributions to unitholders are
based on assumptions that are inherently subjective and are
subject to significant business, economic, financial, legal,
regulatory and competitive risks and uncertainties that could
cause actual cash distributions to differ materially from those
estimated.
The projected cash distributions to trust unitholders in 2011
contained elsewhere in this prospectus are based on VOC
Sponsors calculations, and VOC Sponsor has not received an
opinion or report on such calculations from any independent
accountants. Such calculations are based on assumptions about
drilling, production, crude oil and natural gas prices, hedging
activities, development expenditures, expenses, 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. In
particular, these estimates have assumed that crude oil and
natural gas production is sold in 2011 at NYMEX futures prices
as of of
$ per Bbl in the case of
crude oil and $ per MMBtu in
the case of natural gas. However, actual sales prices may be
significantly lower. Additionally, these estimates assume
Underlying Properties will achieve production volumes set forth
in the reserve reports; however, actual production volumes may
be significantly lower. If prices or production are lower than
expected, the amount of cash available for distribution to trust
unitholders would be reduced.
Actual reserves and future production may be less than
current estimates, which could reduce cash distributions by the
trust and the value of the trust units.
The value of the trust units and the amount of future cash
distributions to the trust unitholders will depend upon, among
other things, the accuracy of the reserves and future production
estimated to be attributable to the trusts interest in the
Underlying Properties. See The Underlying
Properties Reserve reports for a discussion of
the method of allocating proved reserves to the Underlying
Properties and the Net Profits Interest. It is not possible to
measure underground accumulations of oil and natural gas in an
exact way, and estimating reserves is inherently uncertain.
Ultimately, actual production and revenues for the Underlying
Properties could vary negatively and in material amounts from
estimates. Furthermore, development expenditures and production
costs relating to the Underlying Properties could be higher than
current estimates. Petroleum engineers are required to make
subjective estimates of underground accumulations of oil and
natural gas based on factors and assumptions that include:
|
|
|
|
|
historical production from the area compared with production
rates from other producing areas;
|
|
|
|
oil and natural gas prices, production levels, Btu content,
production expenses, transportation costs, severance and excise
taxes and development expenditures; and
|
|
|
|
the effect of expected governmental regulation.
|
Changes in these assumptions and amounts of actual production
and development costs could materially decrease reserve
estimates. In addition, the quantities of recovered reserves
attributable to the Underlying Properties may decrease in the
future as a result of future decreases in the price of oil or
natural gas.
24
The processes of drilling and completing wells are high
risk activities with many uncertainties that could delay or
cancel all or a portion of VOC Sponsors anticipated
drilling schedule and adversely affect future production from
the Underlying Properties. Any such delays or cancellations in
drilling and completion activities could decrease production and
future revenues that are available for distribution to
unitholders.
The processes of drilling and completing wells are subject to
numerous risks beyond the trusts and VOC Sponsors
control, including risks that could delay VOC Sponsors
current drilling schedule and the risk that drilling will not
result in commercially viable oil production. VOC Sponsor is not
obligated to undertake any development activities, so any
drilling and completion activities will be subject to the
reasonable discretion of VOC Sponsor. Further, VOC
Sponsors future business, financial condition, results of
operations, liquidity or ability to finance its share of planned
development expenditures could be materially and adversely
affected by any factor that may curtail, delay or cancel
drilling, including the following:
|
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|
|
delays imposed by or resulting from compliance with regulatory
requirements, including permitting;
|
|
|
|
unusual or unexpected geological formations;
|
|
|
|
shortages of or delays in obtaining equipment and qualified
personnel;
|
|
|
|
equipment malfunctions, failures or accidents;
|
|
|
|
unexpected operational events and drilling conditions;
|
|
|
|
reductions in oil or natural gas prices;
|
|
|
|
market limitations for oil or natural gas;
|
|
|
|
pipe or cement failures;
|
|
|
|
casing collapses;
|
|
|
|
lost or damaged drilling and service tools;
|
|
|
|
loss of drilling fluid circulation;
|
|
|
|
uncontrollable flows of oil and natural gas;
|
|
|
|
fires and natural disasters;
|
|
|
|
environmental hazards, such as oil and natural gas leaks,
pipeline ruptures and discharges of toxic gases;
|
|
|
|
adverse weather conditions; and
|
|
|
|
oil or natural gas property title problems.
|
In the event that drilling of development wells is delayed or
cancelled, or development wells have lower than anticipated
production, due to one of the factors above or for any other
reason, estimated future distributions to unitholders may be
reduced.
25
Risks associated with the production, gathering,
transportation and sale of oil and natural gas could adversely
affect cash distributions by the trust.
The amount of cash to be received by the trust from VOC Sponsor
with respect to the Net Profits Interest, the value of the trust
units and the amount of cash distributions to the trust
unitholders will depend upon, among other things, oil and
natural gas production and prices and the costs incurred by VOC
Sponsor to develop and produce oil and natural gas reserves
attributable to the Underlying Properties. Drilling, production
or transportation accidents as well as adverse weather
conditions that temporarily or permanently halt the production
and sale of oil or natural gas at any of the Underlying
Properties will reduce trust distributions by reducing the
amount of net proceeds available for distribution. For example,
accidents may occur that result in personal injuries, property
damage, damage to productive formations or equipment and
environmental damages. To the extent VOC Sponsor is not able to
recover from insurance any costs incurred by VOC Sponsor in
connection with any such accidents, the net proceeds available
for distribution to the trust may be reduced or delayed. In
addition, curtailments or damage to pipelines used by VOC
Sponsor to transport oil and natural gas production to markets
for sale could reduce the amount of net proceeds available for
distribution. Any such curtailment or damage to the gathering
systems used by VOC Sponsor could also require VOC Sponsor to
find alternative means to transport the oil and natural gas
production from the Underlying Properties, which could require
VOC Sponsor to incur additional costs that will have the effect
of reducing net proceeds available for distribution.
VOC Sponsor does not have any long term contracts related
to the sale of production of oil and natural gas from the
Underlying Properties and may be unable to find purchasers. The
inability to sell all of the production or the failure of any
purchaser to pay VOC Sponsor for the production that has been
delivered could reduce net proceeds attributable to the Net
Profits Interest and thereby reduce cash available for
distribution to the trust unitholders.
VOC Sponsor does not have any firm commitment contracts for the
sale of any production nor has it received security or other
guaranty of payment for the production it sells. Therefore,
there can be no assurance that VOC Sponsor will be able to find
buyers for its production, that buyers will pay the purchase
price therefor or that the price at which the production is sold
will be current market price for such hydrocarbon at the time of
delivery. Currently, VOC Sponsor sells approximately 32% of the
oil produced from the Underlying Properties to MV Purchasing
LLC, an affiliate of VOC Sponsor. Any nonpayment by a purchaser
of production, including MV Purchasing LLC, or inability by VOC
Sponsor to sell any production, could reduce cash available for
distribution to trust unitholders.
The trust is passive in nature and neither the trust nor
the trust unitholders will have voting rights in, or managerial,
contractual or other ability to influence, VOC Sponsor or the
ability to control the field operations of, sale of oil and
natural gas from, or development of, the Underlying
Properties.
Trust unitholders have no voting rights with respect to VOC
Sponsor and therefore will have no managerial, contractual or
other ability to influence VOC Sponsors activities or the
operations of the Underlying Properties. Oil and natural gas
properties are typically managed pursuant to an operating
agreement among the working interest owners of oil and natural
gas properties. The VOC Operators operate, or operate on a
contract basis, substantially all of the properties comprising
the Underlying Properties. The typical operating agreement
contains procedures whereby the owners of the working interests
in the property designate one of the interest owners to be the
operator of the property. Under these arrangements, the operator
is typically responsible for making all decisions relating to
drilling activities, sale of production, compliance with
regulatory requirements and other matters that affect the
property.
26
Shortages or increases in costs of equipment, services and
qualified personnel could result in a reduction in the amount of
cash available for distribution to the trust unitholders.
The demand for qualified and experienced personnel to conduct
field operations, geologists, geophysicists, engineers and other
professionals in the oil and natural gas industry can fluctuate
significantly, often in correlation with oil and natural gas
prices, causing periodic shortages. Historically, there have
been shortages of drilling rigs and other equipment as demand
for rigs and equipment has increased along with the number of
wells being drilled. These factors also cause significant
increases in costs for equipment, services and personnel. Higher
oil and natural gas prices generally stimulate demand and result
in increased prices for drilling rigs, crews and associated
supplies, equipment and services. Shortages of field personnel
and equipment or price increases could significantly decrease
the amount of cash available for distribution to the trust
unitholders or restrict the ability of VOC Sponsor to drill the
development wells and conduct the operations which it currently
has planned for the Underlying Properties.
The trust units may lose value as a result of title
deficiencies with respect to the Underlying Properties.
VOC Sponsor acquired the Underlying Properties over the past
30 years, and at the time of its acquisition of each of the
Underlying Properties, VOC Sponsor retained outside counsel to
examine title to the Underlying Properties as to the acquired
interests. VOC Sponsor subsequently retained outside counsel to
update title to the Underlying Properties in September 2010. The
existence of a material title deficiency with respect to the
Underlying Properties could reduce the value of a property or
render it worthless, thus adversely affecting the distributions
to trust unitholders. VOC Sponsor does not obtain title
insurance covering mineral leaseholds, and VOC Sponsors
failure to cure any title defects may cause VOC Sponsor to lose
its rights to production from the Underlying Properties. In the
event of any such material title problem, proceeds available for
distribution to trust unitholders and the value of the trust
units may be reduced.
VOC Sponsor may transfer all or a portion of the
Underlying Properties at any time, subject to specified
limitations. Under these circumstances, trust unitholders will
have no ability to prevent VOC Sponsor from transferring the
Underlying Properties to another operator, even if the trust
unitholders do not believe that operator would operate the
Underlying Properties in the same manner as VOC Sponsor.
VOC Sponsor may at any time transfer all or part of the
Underlying Properties, subject to and burdened by the Net
Profits Interest, and may abandon individual wells or properties
that it reasonably believes to be uneconomic. For the years
ended December 31, 2007, 2008 and 2009, VOC Sponsor plugged
and abandoned zero, six and 15 wells, respectively, located
on leases on the Underlying Properties. Trust unitholders will
not be entitled to vote on any transfer of the Underlying
Properties, and the trust will not receive any proceeds from any
such transfer, except in the limited circumstances when the Net
Profits Interest is released in connection with such transfer,
in which case the trust will receive an amount equal to the fair
market value (net of sales costs) of the Net Profits Interest
released. See The Underlying Properties Sale
and abandonment of Underlying Properties. Following any
sale or transfer of any of the Underlying Properties, if the Net
Profits Interest is not released in connection with such sale or
transfer, the Net Profits Interest will continue to burden the
transferred property and net proceeds attributable to such
property will be calculated as part of the computation of net
proceeds described in this prospectus. VOC Sponsor may delegate
to the transferee responsibility for all of VOC Sponsors
obligations relating to the Net Profits Interest on the portion
of the Underlying Properties transferred.
In addition, VOC Sponsor may, without the consent of the trust
unitholders, require the trust to release the Net Profits
Interest associated with any lease that accounts for less than
or equal to 0.25% of the total production from the Underlying
Properties in the prior 12 months and
27
provided that the Net Profits Interest covered by such releases
cannot exceed, during any
12-month
period, an aggregate fair market value to the trust of $500,000.
These releases will be made only in connection with a sale by
VOC Sponsor of the relevant Underlying Properties and are
conditioned upon the trusts receiving an amount equal to
the fair market value to the trust of such Net Profits Interest.
Any net sales proceeds paid to the trust will be distributable
to trust unitholders for the quarter in which they are received.
VOC Sponsor has not identified for sale any of the Underlying
Properties.
As the designated operator of a property comprising the
Underlying Properties, VOC Sponsor may enter into farm-out,
operating, participation and other similar agreements to develop
the property. VOC Sponsor may enter into any of these agreements
without the consent or approval of the trustee or any trust
unitholder.
The reserves attributable to the Underlying Properties are
depleting assets and production from those properties will
diminish over time. Furthermore, the trust is precluded from
acquiring other oil and natural gas properties or net profits
interests to replace the depleting assets and production.
Therefore, proceeds to the trust and cash distributions to
unitholders will decrease over time.
The proceeds payable to the trust attributable to the Net
Profits Interests are derived from the sale of production of oil
and natural gas from the Underlying Properties. The reserves
attributable to the Underlying Properties are depleting assets,
which means that the reserves and the quantity of oil and
natural gas produced from the Underlying Properties will decline
over time. Based on the estimated production volumes in the
reserve reports, the oil and natural gas production from proved
reserves attributable to the Underlying Properties is projected
to decline at an average rate of approximately 6.7% per year
over the next 20 years, assuming the level of development
drilling and development expenditures on the Underlying
Properties disclosed elsewhere in this prospectus through 2014
and none thereafter. Actual decline rates may vary from this
projected decline rate. In the event expected future development
is delayed, reduced or cancelled, the average rate of decline
will likely exceed 6.7% per year.
Future maintenance projects on the Underlying Properties may
affect the quantity of proved reserves that can be economically
produced from wells on the Underlying Properties. The timing and
size of these projects will depend on, among other factors, the
market prices of oil and natural gas. In addition, because VOC
Sponsor has agreed to limit the amount of development
expenditures that will be taken into account in calculating net
proceeds attributable to the Net Profits Interest during the
three year-period prior to the termination of the Net Profits
Interest, VOC Sponsor may choose to delay certain development
projects that may otherwise benefit the trust unitholders until
the termination of the trust. VOC Sponsor has no contractual
obligation to develop or otherwise make development expenditures
on the Underlying Properties in the future. Furthermore, with
respect to properties for which VOC Sponsor is not designated as
the operator, VOC Sponsor has limited or no control over the
timing or amount of those development expenditures. VOC Sponsor
also has the right to non-consent and not participate in the
development expenditures on properties for which it is not the
operator, in which case VOC Sponsor and the trust will not
receive the production resulting from such development
expenditures. If VOC Sponsor or other operators do not implement
maintenance projects on the Underlying Properties when
warranted, the future rate of production decline of proved
reserves may be higher than the rate currently expected by VOC
Sponsor or estimated in the reserve report.
The trust agreement will provide that the trusts business
activities will be limited to owning the Net Profits Interest
and any activity reasonably related to such ownership, including
activities required or permitted by the terms of the conveyance
related to the Net Profits Interest. As a
28
result, the trust will not be permitted to acquire other oil and
natural gas properties or net profits interests to replace the
depleting assets and production attributable to the Net Profits
Interest.
Because the net proceeds payable to the trust are derived from
the sale of depleting assets, the portion of the distributions
to unitholders attributable to depletion may be considered to
have the effect of a return of capital as opposed to a return on
investment. Eventually, the Net Profits Interest may cease to
produce in commercial quantities and the trust may, therefore,
cease to receive any distributions of net proceeds therefrom.
The amount of cash available for distribution by the trust
will be reduced by the amount of any costs and expenses related
to the Underlying Properties and other costs and expenses
incurred by the trust.
The trust will bear its share of all costs and expenses related
to the Underlying Properties, such as lease operating expenses,
production and property taxes, development expenses and hedge
expenses, which will reduce the amount of cash received by the
trust. Accordingly, higher costs and expenses related to the
Underlying Properties will directly decrease the amount of cash
received by the trust in respect of its Net Profits Interest.
Please read The Underlying Properties Selected
historical and unaudited pro forma financial data and operating
data of the Underlying Properties. Historical costs may
not be indicative of future costs. In addition, cash available
for distribution by the trust will be further reduced by the
trusts general and administrative expenses, which are
expected to be $900,000 in 2011. For details about these general
and administrative expenses, please see Description of the
trust agreement Fees and expenses.
If production and development costs on the Underlying Properties
together with the other costs exceed gross proceeds of
production from the Underlying Properties, the trust will not
receive net proceeds from those properties until future gross
proceeds from production exceed the total of the excess costs,
plus accrued interest. Development activities may not generate
sufficient additional revenue to repay the costs.
The trustee may, under certain circumstances, sell the Net
Profits Interest and dissolve the trust prior to the expected
termination of the trust. As a result, trust unitholders may not
recover their investment.
The trustee must sell the Net Profits Interest if the holders of
a majority of the trust units approve the sale or vote to
dissolve the trust. The trustee must also sell the Net Profits
Interest if the annual gross proceeds from the Underlying
Properties attributable to the Net Profits Interest are less
than $1.0 million for each of any two consecutive years.
The sale of the Net Profits Interest will result in the
dissolution of the trust. The net proceeds of any such sale will
be distributed to the trust unitholders.
VOC Partners, LLC may sell trust units in the public or
private markets, and such sales could have an adverse impact on
the trading price of the trust units.
After the closing of the offering, VOC Partners, LLC will hold
an aggregate
of
trust units, assuming no exercise of the underwriters
over-allotment option. VOC Partners, LLC has agreed not to sell
any trust units for a period of 180 days after the date of
this prospectus without the consent of Raymond James &
Associates, Inc. See Underwriting. After such
period, VOC Partners, LLC may sell trust units in the public or
private markets, and any such sales could have an adverse impact
on the price of the trust units or on any trading market that
may develop. The trust has granted registration rights to VOC
Partners, LLC, which, if exercised, would facilitate sales of
common units thereby.
29
There has been no public market for the trust units and no
independent appraisal of the value of the Net Profits Interest
has been performed.
Among the factors to be considered in determining the number of
trust units to be offered hereby and the initial public offering
price will be current and historical oil and natural gas prices,
current and prospective conditions in the supply and demand for
oil and natural gas, reserve and production quantities estimated
for the Net Profits Interest, the trusts cash
distributions prospects and prevailing market conditions. None
of VOC Sponsor, the trust or the underwriters will obtain any
independent appraisal or other opinion of the value of the Net
Profits Interest, other than the reserve report prepared by
Cawley, Gillespie & Associates, Inc.
The trading price for the trust units may not reflect the
value of the Net Profits Interest held by the trust.
The trading price for publicly traded securities similar to the
trust units tends to be tied to recent and expected levels of
cash distributions. The amounts available for distribution by
the trust will vary in response to numerous factors outside the
control of the trust, including prevailing prices for sales of
oil and natural gas production from the Underlying Properties
and the timing and amount of production and development costs.
Consequently, the trading price for the trust units may not
necessarily be indicative of the value that the trust would
realize if it sold the Net Profits Interest to a third-party
buyer. In addition, such market price may not necessarily
reflect the fact that since the assets of the trust are
depleting assets, a portion of each cash distribution paid on
the trust units should be considered by investors as a return of
capital, with the remainder being considered as a return on
investment. As a result, distributions made to a unitholder over
the life of these depleting assets may not equal or exceed the
purchase price paid by the unitholder.
Conflicts of interest could arise between VOC Sponsor and
its affiliates, on the one hand, and the trust unitholders, on
the other hand.
As working interest owners in, and operators of substantially
all the wells on, the Underlying Properties, VOC Sponsor and its
affiliates could have interests that conflict with the interests
of the trust and the trust unitholders. For example:
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VOC Sponsors interests may conflict with those of the
trust and the trust unitholders in situations involving the
development, maintenance, operation or abandonment of the
Underlying Properties. VOC Sponsor may also make decisions with
respect to development expenditures that adversely affect the
Underlying Properties. These decisions include reducing
development expenditures on these properties, which could cause
oil and natural gas production to decline at a faster rate and
thereby result in lower cash distributions by the trust in the
future.
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VOC Sponsor may sell some or all of the Underlying Properties
without taking into consideration the interests of the trust
unitholders. Such sales may not be in the best interests of the
trust unitholders. These purchasers may lack VOC Sponsors
experience or its credit worthiness. VOC Sponsor also has the
right, under certain circumstances, to cause the trust to
release all or a portion of the Net Profits Interest in
connection with a sale of a portion of the Underlying Properties
to which such Net Profits Interest relates. In such an event,
the trust is entitled to receive the fair value (net of sales
costs) of the Net Profits Interest released. See The
Underlying Properties Sale and abandonment of
Underlying Properties.
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MV Purchasing LLC, an affiliate of VOC Sponsor, is expected to
market
and/or
purchase a substantial portion of the oil produced from the
Underlying Properties, and it is expected to profit from this
arrangement. Provisions in the Net Profits Interest conveyance,
however, require that charges and other terms under contracts
with affiliates of VOC Sponsor be comparable to prices and other
terms prevailing in the area for similar services or sales.
During the nine months ended September 30, 2010, VOC
Sponsor has sold approximately 32% of the oil produced from the
Underlying Properties to MV Purchasing, LLC, an affiliate of VOC
Sponsor.
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VOC Partners, LLC has registration rights and can sell its units
without considering the effects such sale may have on trust unit
prices or on the trust itself. Additionally, VOC Partners, LLC
can vote its trust units in its sole discretion without
considering the interests of the other trust unitholders.
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The trust is managed by a trustee who cannot be replaced
except by a majority vote of the unitholders at a special
meeting, which may make it difficult for unitholders to remove
or replace the trustee.
The business and affairs of the trust will be managed by the
trustee. Your voting rights as a trust unitholder are more
limited than those of stockholders of most public corporations.
For example, there is no requirement for annual meetings of
trust unitholders or for an annual or other periodic re-election
of the trustee. The trust agreement provides that the trustee
may only be removed and replaced by the holders of a majority of
the outstanding trust units, including trust units held by VOC
Partners, LLC, at a special meeting of trust unitholders called
by either the trustee or the holders of not less than 10% of the
outstanding trust units. As a result, it will be difficult for
public unitholders to remove or replace the trustee without the
cooperation of VOC Partners, LLC so long as it holds a
significant percentage of total trust units.
Trust unitholders have limited ability to enforce
provisions of the Net Profits Interest, and VOC Sponsors
liability to the trust is limited.
The trust agreement permits the trustee to sue VOC Sponsor or
any other future owner of the Underlying Properties to enforce
the terms of the conveyance creating the Net Profits Interest.
If the trustee does not take appropriate action to enforce
provisions of the conveyance, trust unitholders recourse
would be limited to bringing a lawsuit against the trustee to
compel the trustee to take specified actions. The trust
agreement expressly limits a trust unitholders ability to
directly sue VOC Sponsor or any other third party other than the
trustee. As a result, trust unitholders will not be able to sue
VOC Sponsor or any future owner of the Underlying Properties to
enforce these rights. Furthermore, the Net Profits Interest
conveyance provides that, except as set forth in the conveyance,
VOC Sponsor will not be liable to the trust for the manner in
which it performs its duties in operating the Underlying
Properties as long as it acts without gross negligence or
willful misconduct.
Courts outside of Delaware may not recognize the limited
liability of the trust unitholders provided under Delaware
law.
Under the Delaware Statutory Trust Act, trust unitholders
will be entitled to the same limitation of personal liability
extended to stockholders of corporations under the General
Corporation Law of the state of Delaware. No assurance can be
given, however, that the courts in jurisdictions outside of
Delaware will give effect to such limitation.
31
The operations of the Underlying Properties are subject to
environmental laws and regulations that may result in
significant costs and liabilities, which could reduce the amount
of cash available for distribution to trust unitholders.
The oil and natural gas exploration and production operations of
VOC Sponsor are subject to stringent and comprehensive federal,
state and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to
environmental protection. These laws and regulations may impose
numerous obligations that apply to VOC Sponsors
operations, including the requirement to obtain a permit before
conducting drilling, waste disposal or other regulated
activities; the restriction of types, quantities and
concentrations of materials that can be released into the
environment; the incurrence of significant development
expenditures to install pollution or safety-related controls at
the operated facilities; the limitation or prohibition of
drilling activities on certain lands lying within wilderness,
wetlands and other protected areas; and the imposition of
substantial liabilities for pollution resulting from operations.
Numerous governmental authorities, such as the
U.S. Environmental Protection Agency (EPA) and
analogous state agencies, have the power to enforce compliance
with these laws and regulations and the permits issued under
them, oftentimes requiring difficult and costly actions. Failure
to comply with these laws and regulations may result in the
assessment of administrative, civil or criminal penalties; the
imposition of investigatory or remedial obligations; and the
issuance of injunctions limiting or preventing some or all of
VOC Sponsors operations. Furthermore, the inability to
comply with environmental laws and regulations in a
cost-effective manner, such as removal and disposal of produced
water and other generated oil and gas wastes, could impair VOC
Sponsors ability to produce oil and natural gas
commercially from the Underlying Properties, which would reduce
proceeds attributable to the Net Profits Interest.
There is inherent risk of incurring significant environmental
costs and liabilities in the performance of VOC Sponsors
operations as a result of its handling of petroleum hydrocarbons
and wastes, air emissions and wastewater discharges related to
its operations, and historical industry operations and waste
disposal practices. Under certain environmental laws and
regulations, VOC Sponsor could be subject to joint and several
strict liability for the removal or remediation of previously
released materials or property contamination regardless of
whether VOC Sponsor was responsible for the release or
contamination or whether 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
VOC Sponsors wells are drilled and facilities where VOC
Sponsors petroleum hydrocarbons or wastes are taken for
reclamation or disposal, may also 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 damage. In addition, the risk of
accidental spills or releases could expose VOC Sponsor to
significant liabilities that could have a material adverse
effect on its financial condition or results of operations.
Changes in environmental laws and regulations occur frequently,
and any changes that result in more stringent or costly
operational control requirements or waste handling, storage,
transport, disposal or cleanup requirements could require VOC
Sponsor to make significant expenditures to attain and maintain
compliance and may otherwise have a material adverse effect on
its results of operations, competitive position or financial
condition. VOC Sponsor may be unable to recover some or any of
these costs from insurance, in which case the amount of cash
received by the trust may be decreased. The Net Profits Interest
held by the trust will bear 80% of all costs and expenses
incurred by VOC Sponsor in regard to environmental costs and
liabilities associated with the Underlying Properties, including
costs and liabilities resulting from conditions that existed
prior to VOC Sponsors acquisition of the Underlying
Properties unless such costs and expenses result from VOC
Sponsors negligence or misconduct. In addition, as a
result of the increased cost of compliance, VOC Sponsor may
decide to discontinue drilling.
32
The operations of the Underlying Properties are subject to
complex federal, state, local and other laws and regulations
that could adversely affect the cost, manner or feasibility of
conducting its operations or expose VOC Sponsor to significant
liabilities, which could reduce the amount of cash available for
distribution to trust unitholders.
The production and development operations of the Underlying
Properties are subject to complex and stringent laws and
regulations. In order to conduct its operations in compliance
with these laws and regulations, VOC Sponsor must obtain and
maintain numerous permits, drilling bonds, approvals and
certificates from various federal, state and local governmental
authorities and engage in extensive reporting. VOC Sponsor may
incur substantial costs in order to maintain compliance with
these existing laws and regulations, and the Net Profits
Interest will bear its share of these costs. In addition, VOC
Sponsors costs of compliance may increase if existing laws
and regulations are revised or reinterpreted, or if new laws and
regulations become applicable to VOC Sponsors operations.
Such costs could have a material adverse effect on VOC
Sponsors business, financial condition and results of
operations and reduce the amount of cash received by the trust.
VOC Sponsor must also comply with laws and regulations
prohibiting fraud and market manipulations in energy markets. To
the extent VOC Sponsor is a shipper on interstate pipelines, it
must comply with the tariffs of such pipelines and with federal
policies related to the use of interstate capacity, and such
compliance costs will be borne in part by the trust.
Laws and regulations governing exploration and production may
also affect production levels. VOC Sponsor is required to comply
with federal and state laws and regulations governing
conservation matters, including: provisions related to the
unitization or pooling of the oil and natural gas properties;
the establishment of maximum rates of production from wells; the
spacing of wells; the plugging and abandonment of wells; and the
removal of related production equipment. These and other laws
and regulations can limit the amount of oil and natural gas VOC
Sponsor can produce from its wells, limit the number of wells it
can drill, or limit the locations at which it can conduct
drilling operations, which in turn could negatively impact trust
distributions, estimated and actual future net revenues to the
trust and estimates of reserves attributable to the trusts
interests.
New laws or regulations, or changes to existing laws or
regulations, may unfavorably impact VOC Sponsor, could result in
increased operating costs or have a material adverse effect on
VOC Sponsors financial condition and results of operations
and reduce the amount of cash received by the trust. For
example, Congress is currently considering legislation that, if
adopted in its proposed form, would subject companies involved
in oil and natural gas exploration and production activities to,
among other items, additional regulation of and restrictions on
hydraulic fracturing of wells, the elimination of certain
U.S. federal tax incentives and deductions available to oil
and natural gas exploration and production activities, and the
prohibition or additional regulation of private energy commodity
derivative and hedging activities. These and other potential
regulations could increase the operating costs of the Underlying
Properties, reduce VOC Sponsors liquidity, delay VOC
Sponsors operations or otherwise alter the way VOC Sponsor
conducts its business, any of which could have a material
adverse effect on the trust and the trusts cash flows.
Climate change laws and regulations restricting emissions
of greenhouse gases could result in increased
operating costs and reduced demand for the oil and natural gas
that VOC Sponsor produces while the physical effects of climate
change could disrupt VOC Sponsors
33
production and cause VOC Sponsor to incur significant
costs in preparing for or responding to those effects.
On December 15, 2009, the EPA published its findings that
emissions of carbon dioxide, methane and other greenhouse gases
(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 allow the
agency to adopt and implement regulations that would restrict
emissions of GHGs under existing provisions of the federal Clean
Air Act. In April 2010, the EPA promulgated final motor vehicle
GHG emission standards, which take effect in model year 2012.
According to EPA, the motor vehicle GHG emission standards will
trigger construction and operating permitting requirements for
stationary sources of GHG emissions beginning January 2,
2011. In May 2010, the EPA finalized the Prevention of
Significant Deterioration and Title V GHG Tailoring Rule,
which phases in permitting requirements for stationary sources
of GHG emissions, beginning January 2, 2011 and extending
through June 30, 2013. These EPA rulemakings could affect
VOC Sponsors operations and its ability to obtain air
permits for new or modified facilities. In addition, on
November 30, 2010, the EPA published final regulations
expanding the existing greenhouse gas monitoring and reporting
rule to include onshore and offshore oil and natural gas
production and onshore oil and natural gas processing,
transmission storage and distribution facilities. Reporting of
GHG emissions from such facilities will be required on an annual
basis, with reporting beginning in 2012 for emission occurring
in 2011.
In addition, both houses of Congress have actively considered
legislation to reduce emissions of GHGs, and almost 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. These reductions would be expected to cause the
cost of allowances to escalate significantly over time. The
adoption of any legislation or regulations that requires
reporting of GHGs or otherwise limits emissions of GHGs from VOC
Sponsors equipment and operations could require VOC
Sponsor to incur costs to monitor and report on GHG emissions or
reduce emissions of GHGs associated with its operations, and
such requirements also could adversely affect demand for the oil
and natural gas produced, all of which could reduce the amount
of cash received by the trust. The adoption and implementation
of any regulations imposing reporting obligations on, or
limiting emissions of GHGs from, VOC Sponsors equipment
and operations could require VOC Sponsor to incur costs to
reduce emissions of GHGs associated with its operations or could
adversely affect demand for the natural gas that it produces,
each of which could adversely impact the trusts share of
net profits.
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, they could have an
adverse effect on VOC Sponsors assets and operations and,
consequently, may reduce the amount of cash received by the
trust.
Federal and state legislative and regulatory initiatives
relating to hydraulic fracturing could result in increased costs
and additional operating restrictions or delays as well as
adversely affect VOC Sponsors services.
Hydraulic fracturing is an important and common practice that is
used to stimulate production of hydrocarbons, particularly
natural gas, from tight formations. The process involves
34
the injection of water, sand and chemicals under pressure into
formations to fracture the surrounding rock and stimulate
production. The process is typically regulated by state oil and
gas commissions but is not subject to regulation at the federal
level. The EPA has commenced a study of the potential
environmental impacts of hydraulic fracturing activities, with
results of the study anticipated to be available by late 2012,
and a committee of the U.S. House of Representatives is
also conducting an investigation of hydraulic fracturing
practices. Legislation has been introduced before Congress to
provide for federal regulation of hydraulic fracturing and to
require disclosure of the chemicals used in the fracturing
process. In addition, some states have adopted, and other states
are considering adopting, regulations that could restrict
hydraulic fracturing in certain circumstances. For example, New
York has imposed a de facto moratorium on the issuance of
permits for high-volume, horizontal hydraulic fracturing until
state-administered environmental studies are finalized, a draft
of which must be published by June 1, 2011, followed by a
30-day
comment period. Further, Pennsylvania has adopted a variety of
regulations limiting how and where fracturing can be performed.
If new laws or regulations that significantly restrict hydraulic
fracturing are passed by Congress or adopted in Texas or Kansas
such legal requirements could make it more difficult or costly
for VOC Sponsor to perform hydraulic fracturing activities and
thereby affect the determination of whether a well is
commercially viable. In addition, if hydraulic fracturing is
regulated at the federal level, VOC Sponsors fracturing
activities could become subject to additional permit
requirements or operational restrictions and also to associated
permitting delays and potential increases in costs. Such federal
or state legislation could require the disclosure of chemical
constituents used in the fracturing process to state or federal
regulatory authorities who could then make such information
publicly available. In addition, restrictions on hydraulic
fracturing could reduce the amount of oil and natural gas that
VOC Sponsor is ultimately able to produce in commercial
quantities from the Underlying Properties.
The bankruptcy of VOC Sponsor or any of the VOC Operators
could impede the operation of the wells and the development of
the proved undeveloped reserves.
VOC Sponsor is a privately-held limited partnership engaged in
the production and development of oil and natural gas from
properties located in Kansas and Texas. The trust is dependent
on VOC Sponsor to implement its planned development and workover
program, including the expenditure over the next five years of
approximately $25.3 million to drill additional wells and
recomplete and workover other wells. Without this development
and workover program, the average decline rate over the life of
the trust of the oil and natural gas production from the proved
reserves attributable to the Underlying Properties will likely
exceed the 6.7% per year projected in the reserve reports. The
VOC Operators are privately-held limited partnerships or
corporations engaged in the operation of oil and natural gas
wells in Kansas and Texas that were the operators or contract
operators of Underlying Properties having approximately 98% of
the total proved reserves on the Underlying Properties, based on
PV-10 value.
Therefore, the value of the Net Profits Interest and the
trusts ultimate cash available for distribution will be
highly dependent on the financial condition of VOC Sponsor and
the VOC Operators. None of VOC Sponsor or the VOC Operators will
be a reporting company following this offering or will file
periodic reports with the SEC. Therefore, as a trust unitholder,
you will not have access to financial information about VOC
Sponsor or the VOC Operators. Furthermore, none of VOC Sponsor
or the VOC Operators has agreed with the trust to maintain a
certain net worth or to be restricted by other similar covenants
and VOC Sponsor intends to distribute all of the net proceeds of
this offering to its partners instead of retaining all or a
portion for the development of the Underlying Properties.
The ability of VOC Sponsor to develop the Underlying Properties
and the ability of the VOC Operators to operate the wells on the
Underlying Properties depends on the future financial condition
and economic performance and access to capital of VOC Sponsor
and the VOC Operators, which in turn will depend upon the supply
and demand for oil and natural gas,
35
prevailing economic conditions and financial, business and other
factors, many of which are beyond the control of VOC Sponsor and
the VOC Operators. See Information about VOC Brazos Energy
Partners, L.P. (VOC Sponsor) found on
page VOC-1
for additional information relating to VOC Sponsor, including
information relating to the business of VOC Sponsor, historical
financial statements of VOC Sponsor and other financial
information relating to VOC Sponsor. This prospectus contains no
financial information about the VOC Operators.
In the event of the bankruptcy of VOC Sponsor or a VOC Operator,
the trust would have to seek a new party to perform the
development and workover program or the operations of the wells
operated by such VOC Operator. The trust may not be able to find
a replacement driller or operator, and it may not be able to
enter into a new agreement with such replacement party on
favorable terms within a reasonable period of time. As a result,
such a bankruptcy may result in reduced production from the
reserves and decreased distributions to trust unitholders.
The trust may be treated as an unsecured creditor with
respect to the Net Profits Interest attributable to properties
in Kansas in the event of the bankruptcy of VOC Sponsor if a
court were to hold that the conveyance and recording of the Net
Profits Interest was not a conveyance of a fully vested real
property interest or an interest in hydrocarbons in place or to
be produced.
Although under Texas law it is well-established that the
recording in the appropriate real property records of an
interest such as the Net Profits Interest will constitute the
conveyance of a fully vested real property interest to the
trust, the law in Kansas is less certain. VOC Sponsor and the
trust believe, based upon an opinion of counsel, that the
recording in the appropriate real property records in Kansas of
the Net Profits Interest should constitute the conveyance of a
fully vested real property interest, interests in hydrocarbons
in place or to be produced or a production payment as such is
defined under the United States Bankruptcy Code; however, there
is no dispositive Kansas Supreme Court case directly addressing
these issues. In a bankruptcy of VOC Sponsor, creditors of VOC
Sponsor would be able to claim the Net Profits Interest as an
asset of the bankruptcy estate to satisfy obligations to them if
the conveyance of the Net Profits Interest did not constitute
the conveyance of a real property interest or interests in
hydrocarbons in place or to be produced under applicable state
law or a production payment, in which case the trust would be an
unsecured creditor of VOC Sponsor at risk of losing the entire
value of the Net Profit Interests to senior creditors.
Due to lack of geographic diversification of the
Underlying Properties, adverse developments in Kansas or Texas
could adversely impact the results of operations and cash flows
of the Underlying Properties and reduce the amount of cash
available for distributions to trust unitholders.
The operations of the Underlying Properties are focused on the
production and development of oil and natural gas within the
states of Kansas and Texas. As a result, the results of
operations and cash flows of the Underlying Properties depend
upon continuing operations in these areas. Due to the lack of
diversification in geographic location, adverse developments in
exploration and production of oil and natural gas in either of
these areas of operation could have a significantly greater
impact on the results of operations and cash flows of the
Underlying Properties than if the operations were more
diversified.
36
The receipt of payments by VOC Sponsor based on the hedge
contracts depends upon the financial position of the hedge
contract counterparties. A default by any of the hedge contract
counterparties could reduce the amount of cash available for
distribution to the trust unitholders.
Payments from hedge contract counterparties to VOC Sponsor are
intended to offset costs and thus have the effect of providing
additional cash to the trust during periods of lower crude oil
prices. In the event that any of the counterparties to the hedge
contracts default on their obligations to make payments to VOC
Sponsor under the hedge contracts, the cash distributions to the
trust unitholders could be materially reduced. VOC Sponsor does
not have any security interest from its hedge counterparties
against which it could recover in the event of a default by any
such counterparty.
VOC Sponsors performance of its obligations to the
trust and the financial results of the trust may not be as
successful as the drilling and financial results of MVO.
As disclosed in this prospectus, certain members of the
management of VOC Sponsor previously participated in the
formation and initial public offering of MVO. The historical
results of operations and performance of the MVO should not be
relied on as an indicator of how this trust will perform.
TAX RISKS
RELATED TO THE TRUSTS TRUST UNITS
The tax treatment of an investment in trust units could be
affected by recent and potential legislative changes, possibly
on a retroactive basis.
The recently enacted Health Care and Education Affordability
Reconciliation Act of 2010 includes a provision that, in taxable
years beginning after December 31, 2012, subjects an
individual having adjusted modified gross income in excess of
$200,000 (or $250,000 for married taxpayers filing joint
returns) to a medicare tax equal generally to 3.8%
of the lesser of such excess or the individuals net
investment income, which appears to include interest income
derived from investments such as the trust units as well as any
net gain from the disposition of trust units. In addition,
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.
The trust has not requested a ruling from the IRS
regarding the tax treatment of ownership of the trust units. If
the IRS were to determine (and be sustained in that
determination) that the trust is not a grantor trust
for federal income tax purposes, or that the Net Profits
Interest is not properly treated as a production payment (and
thus would fail to qualify as a debt instrument) for federal
income tax purposes, the trust unitholders may receive different
and potentially less advantageous tax treatment from that
described in this prospectus.
If the trust were not treated as a grantor trust for federal
income tax purposes, the trust should be treated as a
partnership for such purposes. Although the trust would not
become subject to federal income taxation at the entity level as
a result of treatment as a partnership, and items of income,
gain, loss and deduction would flow through to the trust
unitholders, the trusts tax reporting requirements would
be more complex and costly to implement and maintain, and its
distributions to unitholders could be reduced as a result.
37
If the Net Profits Interest were not treated as a production
payment (and thus would fail to qualify as a debt instrument for
federal income tax purposes) the amount, timing and character of
income, gain, or loss in respect of an investment in the trust
could be affected. See Federal income tax
consequences.
Neither VOC Sponsor nor the trustee has requested a ruling from
the IRS regarding these tax questions, and neither VOC Sponsor
nor the trust can assure you that such a ruling would be granted
if requested or that the IRS will not challenge these positions
on audit.
Trust unitholders should be aware of the possible state tax
implications of owning trust units. See State tax
considerations.
38
FORWARD-LOOKING
STATEMENTS
This prospectus contains forward-looking statements
about VOC Sponsor and the trust that are subject to risks and
uncertainties. All statements other than statements of
historical fact included in this prospectus, including, without
limitation, statements under Prospectus summary and
Risk factors regarding the financial position,
business strategy, production and reserve growth, and other
plans and objectives for the future operations of VOC Sponsor
and the trust are forward-looking statements. Such statements
may be influenced by factors that could cause actual outcomes
and results to differ materially from those projected.
Forward-looking statements are subject to risks and
uncertainties and include statements made in this prospectus
under Projected cash distributions, statements
pertaining to future development activities and costs, and other
statements in this prospectus that are prospective and
constitute forward-looking statements.
When used in this document, the words believes,
expects, anticipates,
intends or similar expressions are intended to
identify such forward-looking statements. The following
important factors, in addition to those discussed elsewhere in
this prospectus, could affect the future results of the energy
industry in general, and VOC Sponsor and the trust in
particular, and could cause actual results to differ materially
from those expressed in such forward-looking statements:
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risks incident to the drilling and operation of oil and natural
gas wells;
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future production and development costs and plans;
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the effect of existing and future laws and regulatory actions;
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the effect of changes in commodity prices;
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the impact of the hedge contracts;
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conditions in the capital markets;
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competition from others in the energy industry;
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uncertainty of estimates of oil and natural gas reserves and
production; and
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inflation.
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You should not place undue reliance on these forward-looking
statements. All forward-looking statements speak only as of the
date of this prospectus. VOC Sponsor does not undertake any
obligation to release publicly any revisions to the
forward-looking statements to reflect events or circumstances
after the date of this prospectus or to reflect the occurrence
of unanticipated events, unless the securities laws require us
to do so.
This prospectus describes other important factors that could
cause actual results to differ materially from expectations of
VOC Sponsor and the trust, including under the heading
Risk factors. All written and oral forward-looking
statements attributable to VOC Sponsor or the trust or persons
acting on behalf of VOC Sponsor or the trust are expressly
qualified in their entirety by such factors.
39
USE OF
PROCEEDS
VOC Sponsor is offering all of the trust units to be sold in
this offering, including the trust units to be sold upon the
exercise of the underwriters over-allotment option. VOC
Sponsor expects to receive net proceeds from the sale
of trust
units offered by this prospectus of approximately
$ million, after deducting
underwriting discounts and commissions, structuring fees and
offering expenses, and an additional
$ million if the underwriters
exercise their option to purchase additional trust units in
full. Forty-five days following the closing of this offering,
VOC Sponsor will sell any trust units not sold in this offering
to VOC Partners, LLC at the initial public offering price.
VOC Sponsor intends to use the net proceeds from this offering,
including any proceeds from the exercise of the
underwriters option to purchase additional trust units and
the sale of trust units to VOC Partners, LLC, to make cash
distributions to its limited partners.
40
VOC
SPONSOR
VOC Brazos is a privately-held limited partnership engaged in
the production and development of oil and natural gas from
properties located in Texas. VOC Brazos was formed in May 2003.
Pursuant to the KEP Acquisition, concurrent with the close of
this offering, VOC Brazos will acquire KEP, which was formed in
November 2009 to develop and produce oil and natural gas from
properties primarily located in Kansas along with a limited
number of Texas properties. There are no conditions to the
closing of the KEP Acquisition other than the closing of this
offering. Members of KEP acquired interests in the properties
owned by KEP through various acquisitions and drilling
activities that have occurred since 1979.
As of December 31, 2009, VOC Sponsor held interests in
approximately 892 gross (550.2 net) producing wells,
and proved reserves of the Underlying Properties were
approximately 13.0 MMBoe. As of December 31, 2009,
based on
PV-10 value,
the VOC Operators were the operators or contract operators of
approximately 98% of the total proved reserves attributable to
the Underlying Properties with Vess Oil operating, on behalf of
VOC Sponsor, approximately 90% of the total proved reserves and
L.D. Drilling Inc. and Davis Petroleum, Inc. operating
approximately 8% of the total proved reserves. Vess Oil has
operated oil and natural gas properties in Kansas for more than
30 years and, according to statistics furnished by the
Kansas Geological Survey, during 2009, was the third largest
operator of oil properties in Kansas measured by production
during 2009. Vess Oil currently operates over 1,600 oil, natural
gas and service wells located primarily in Kansas, with growing
operations in Texas. As of September 30, 2010, Vess Oil
employed 19 full-time employees, three contract
professionals and 14 contract personnel in its Wichita office
and in five field and satellite offices.
The trust units do not represent interests in, or obligations
of, VOC Sponsor.
41
SUMMARY
HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL,
OPERATING AND RESERVE DATA OF VOC SPONSOR
The summary combined financial data presented below should be
read in conjunction with VOC Sponsor Selected
historical and unaudited pro forma data of VOC Sponsor and
the accompanying financial statements and related notes of VOC
Sponsor included elsewhere in this prospectus. In connection
with the closing of this offering, VOC Brazos will acquire the
membership interests in KEP in exchange for partnership
interests in VOC Brazos, resulting in KEP becoming a
wholly-owned subsidiary of VOC Brazos. As the Common Control
Properties are deemed to be under common control with VOC
Brazos, accounting rules specify that VOC Brazos and the Common
Control Properties be combined from the earliest date they came
under common control. The financial data and operations of such
assets are referred to herein as Predecessor, and
are described in more detail in Information about VOC
Brazos Energy Partners, L.P. (VOC Sponsor)
Managements discussion and analysis of financial condition
and results of operations of VOC Sponsor. Accordingly, in
order to give full effect to the acquisition by VOC Brazos of
KEP, the following table includes pro forma financial and
operating data of Predecessor giving effect to the acquisition
of the Acquired Underlying Properties. Since the historical
assets and operations of Predecessor will only represent a
portion of the assets and operations to be held by VOC Sponsor
at the closing of this offering, the future results of
operations of VOC Sponsor will not be comparable to the
historical results of Predecessor.
The summary combined historical financial data of Predecessor as
of December 31, 2007, 2008 and 2009 and for each of the
years in the three-year period ended December 31, 2009 have
been derived from Predecessors audited financial
statements. The summary combined historical financial data of
Predecessor as of September 30, 2009 and 2010 and for the
nine-month periods ended September 30, 2009 and 2010 have
been derived from Predecessors unaudited interim financial
statements. The unaudited combined financial statements were
prepared on a basis consistent with the audited statements and,
in the opinion of VOC Brazos, include all adjustments
(consisting only of normal recurring adjustments) necessary to
present fairly the results of Predecessor for the periods
presented.
The summary combined financial unaudited pro forma financial
data as of and for the year ended December 31, 2009 and as
of and for the nine months ended September 30, 2010 set
forth in the following table have been derived from the
unaudited combined pro forma financial statements of Predecessor
included in this prospectus beginning on
page VOC F-27.
The pro forma adjustments have been prepared as if the
acquisition of the Acquired Underlying Properties and, with
respect to pro forma as adjusted information, the conveyance of
the Net Profits Interest and the offer and sale of the trust
units and application of the net proceeds therefrom, had taken
place (i) on September 30, 2010, in the case of the
pro forma balance sheet information as of September 30,
2010, and (ii) as of January 1, 2009, in the case of
the pro forma statement of
42
earnings information for the year ended December 31, 2009,
and the nine months ended September 30, 2010.
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Predecessor
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Predecessor Pro Forma
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Pro Forma for the
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As Adjusted for the Offering
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Acquisition of the Acquired
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(including the conveyance of
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Underlying Properties
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the Net Profits Interest)
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Predecessor
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Nine Months
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Nine Months
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Nine Months Ended
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Year Ended
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Ended
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Year Ended
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Ended
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Year Ended December 31,
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September 30,
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December 31,
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September 30,
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December 31,
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September 30,
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2007
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2008
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2009
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2009
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2010
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2009
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2010
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2009
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2010
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(In thousands)
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(Unaudited)
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(Unaudited)
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(Unaudited)
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Revenue
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$
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21,290
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$
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32,198
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$
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25,750
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$
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17,949
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$
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29,091
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$
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44,133
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$
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47,073
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$
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15,836
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$
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14,633
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Net earnings
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$
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10,087
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$
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12,839
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$
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10,861
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$
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6,620
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$
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16,557
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$
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17,222
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$
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25,510
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$
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9,230
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$
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9,269
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Total assets (at period end)
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$
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108,830
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$
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101,280
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$
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109,626
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$
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173,271
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$
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85,220
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Long-term liabilities, excluding current maturities (at period
end)
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$
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37,018
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$
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28,315
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$
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26,765
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$
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28,822
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$
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102,264
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The table below includes selected production and reserve
information for VOC Sponsor for the periods presented.
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Nine Months
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Ended
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September
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Year Ended December 31,
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30,
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Historical Results
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2007
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2008
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2009
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2009
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2010
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Production (MBoe)
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828
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829
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847
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631
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705
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Net proved reserves (MBoe) (at period end)
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13,223
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10,821
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13,007
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Net proved developed reserves (MBoe) (at period end)
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12,603
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10,046
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11,536
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MANAGEMENT
OF VOC SPONSOR
VOC Sponsor does not currently have any executive officers,
directors or employees. Instead, VOC Sponsor is managed by an
executive management team consisting of certain officers and
employees of Vess Oil on behalf of the general partner, Vess
Texas Partners, LLC. None of the members of the executive
management team of Vess Oil who perform management functions for
VOC Sponsor receive any direct compensation from the trust or
from VOC Sponsor.
43
Set forth in the table below are the names, ages, and titles at
Vess Oil of the members of the executive management team of Vess
Oil who perform management functions on behalf of Vess Texas
Partners, LLC, VOC Sponsors general partner:
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Name
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Age
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Title
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J. Michael Vess
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59
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President and Chief Executive Officer
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William R. Horigan
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61
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Vice President of Operations
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Brian Gaudreau
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55
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Vice President of Land
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Barry Hill
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34
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Vice President and Chief Financial Officer
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Alan Howarter
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54
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Vice President of Financial Reporting
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EXECUTIVE
MANAGEMENT FROM VESS OIL
J. Michael Vess is the President, Chief Executive
Officer and principal owner of Vess Oil. Mr. Vess
co-founded Vess Oil in 1979 and continues to be responsible for
the coordination and supervision of exploration and production
and the acquisition of its oil and natural gas reserves.
Mr. Vess received a Bachelor of Business Administration
degree from Wichita State University in 1973 and subsequently
received his CPA certificate. Mr. Vess currently serves on
the Board of Directors and Executive Committees for the Kansas
Independent Oil and Gas Association (KIOGA) and is
the current Chairman of the KIOGA Committee on Electricity. In
addition, he is Past Chairman of the KIOGA Tax Committee and a
current member of the Interstate Oil and Gas Compact Commission
Outreach Committee.
William R. Horigan is the Vice President of Operations
for Vess Oil where he is responsible for the engineering,
enhancement and exploitation of its existing properties as well
as the engineering analysis and evaluation of its future reserve
acquisitions. Mr. Horigan joined Vess Oil in 1988 as
Operations Manager. Prior to joining Vess Oil, Mr. Horigan
served in various petroleum engineering capacities for Amoco
Production Company beginning in 1975. Mr. Horigan later
served as Division Operations Manager for Slawson Oil
Company. Mr. Horigan graduated from the University of
Kansas in 1974 with a Bachelor of Science degree in Chemical
Engineering. Mr. Horigan is a member of the Society of
Petroleum Engineers and has served on the Executive Board for
the Wichita Section. He is also a member of the Producers
Advisory Board of the KU Tertiary Oil Recovery Project and
a member of the Petroleum Technology Transfer Council of the
North Mid-Continent Region.
Brian Gaudreau is the Vice President of Land for Vess Oil
where he is responsible for land, contracts and acquisitions.
Mr. Gaudreau joined Vess Oil in 2002 as Vice President,
Land and Acquisitions. Prior to joining Vess Oil, he held the
title of Manager, Land and Acquisitions for Stelbar Oil
Corporation, Inc. beginning in 1989. Mr. Gaudreau graduated
from the University of Kansas in 1977 with a Bachelors degree in
Economics. Mr. Gaudreau belongs to the American Association
of Professional Landmen, is a Director and serves on the
Executive Committee of KIOGA, and belongs to the Dallas
Acquisitions, Divestitures, and Mergers Energy Forum.
Barry Hill is the Vice President and Chief Financial
Officer for Vess Oil responsible for planning, directing and
coordinating finance activities. Mr. Hill joined Vess Oil
in February 2010. Prior to joining Vess Oil, Mr. Hill spent
approximately ten years in the Energy Investment Banking group
of Raymond James and Associates, Inc., most recently as Vice
President, completing numerous public equity offerings, advisory
engagements and private securities assignments for a wide
spectrum of energy industry clients, including many exploration
and production companies. Mr. Hill earned his A.B. in
Economics with honors from Harvard College in 1998 and an M.B.A.
from the Darden Graduate School of Business at the University of
Virginia in 2003.
44
Alan Howarter is the Vice President of Financial
Reporting for Vess Oil responsible for the financial reporting
aspects of Vess Oil and other related entities.
Mr. Howarter joined Vess Oil in 2007. Prior to joining Vess
Oil, Mr. Howarter was a Manager at Regier Carr &
Monroe, L.L.P. Previously, Mr. Howarter was a Partner and
head of the Audit Department of the Wichita office of Grant
Thornton, LLP. Mr. Howarter received his Bachelor of
Business Administration degree in Accounting from Wichita State
University in 1978. He is a licensed CPA in Kansas.
Mr. Howarter is currently a member of the Accounting
Advisory Board of Wichita State University, the American
Institute of Certified Public Accountants, the Kansas Society of
Certified Public Accountants and the Petroleum Accountants
Society of Kansas. He is also a past president and treasurer of
the Petroleum Accountants Society of Kansas.
BENEFICIAL
OWNERSHIP OF VOC SPONSOR
The following table sets forth, as of December 28, 2010,
the beneficial ownership of limited partnership interests of VOC
Sponsor that will be outstanding after giving effect to the
consummation of this offering including the KEP Acquisition and
held by:
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each person who will then beneficially own 5% or more of the
outstanding partner interests in VOC Sponsor;
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each member of Vess Oils executive management team, who
perform management functions on behalf of VOC Sponsor; and
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all members of Vess Oils executive management team, who
perform management functions on behalf of VOC Sponsor, as a
group.
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Except as indicated by footnote, the persons named in the table
below have sole voting and investment power with respect to all
partnership interests of VOC Sponsor shown as beneficially owned
by them.
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Percentage of
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Partnership Interests
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Name of Beneficial Owner
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Beneficially Owned
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L. D. Davis (1)
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25.8
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%
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J. Michael Vess (2)
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22.0
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%
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CPC Brazos Energy, L.P. (3)
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17.2
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%
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William Price (4)
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9.1
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%
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C. J. Lett (5)
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8.6
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%
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William R. Horigan (6)
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6.1
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%
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Brian Gaudreau (7)
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2.2
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%
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Barry Hill
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*
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Alan Howarter (8)
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*
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Executive Management as a Group (2)(6)(7)(8)
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30.5
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%
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*
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less than 1%
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(1)
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Includes interests indirectly
beneficially owned in VOC Sponsor through several entities,
including through interests in Davis Energy LLC, which entity
beneficially owns a 13.3% interest in VOC Sponsor. The address
of Mr. Davis is 7 SW 26th Ave., Great Bend, Kansas 67530.
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(2)
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Includes 13.7% of
Mr. Vess interests in VOC Sponsor indirectly
beneficially owned through family trusts. Mr. Vess also has
dispositive power over an additional 8.3% of VOC Sponsor. The
address of Mr. Vess is 1700 Waterfront Parkway, Building
500, Wichita, Kansas 67206.
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45
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(3)
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The address of CPC Brazos Energy,
L.P., an entity sponsored by Carson Private Capital, is 500
Victory Plaza East, 3030 Olive Street, Dallas, Texas 75219.
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(4)
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Includes interests indirectly
beneficially owned through several entities. The address of
Mr. Price is 1700 Waterfront Parkway,
Building 500, Wichita, KS 67206.
|
|
(5)
|
|
Includes interests indirectly
beneficially owned through several entities. The address of
Mr. Lett is 9320 E. Central, Wichita, Kansas
67206.
|
|
(6)
|
|
Includes interests indirectly
beneficially owned through several entities. The address of
Mr. Horigan is 1700 Waterfront Parkway, Building 500,
Wichita, Kansas 67206.
|
|
(7)
|
|
Includes interests indirectly
beneficially owned through several entities. The address of
Mr. Gaudreau is 1700 Waterfront Parkway, Building 500,
Wichita, Kansas 67206.
|
|
(8)
|
|
Mr. Howarter beneficially owns
less than 1% of VOC Brazos through his beneficial ownership of
10% of the membership interests in Vess Oil Company, L.L.C., an
indirect subsidiary of VOC Sponsor. The address of
Mr. Howarter is 1700 Waterfront Parkway, Building 500,
Wichita, Kansas 67206
|
BENEFICIAL
OWNERSHIP OF VOC ENERGY TRUST
|
|
|
|
|
|
|
Class of
|
|
Percentage
|
Name of Beneficial
Owner
|
|
Securities
|
|
of Ownership
|
|
VOC Partners, LLC (1)
|
|
Trust Units
|
|
34.8% (2)
|
|
|
|
(1)
|
|
The parties who beneficially own
VOC Sponsor as set forth in the table above own VOC Partners,
LLC in the same proportion as they own VOC Sponsor. However,
such ownership percentage described in the table above does not
take into account Class B Units of VOC Partners, LLC. Such
Class B Units are issuable to VOC Management Group at the
discretion of VOC Partners, LLC, and these units may equal up to
1.5% of the outstanding units of VOC Partners, LLC.
|
|
(2)
|
|
VOC Partners, LLC has entered into
an agreement to acquire from VOC Sponsor all trust units not
sold by VOC Sponsor in this offering at the initial offerings
price. The closing of such transaction will occur forty-five
days following the closing of this offering.
|
46
MV OIL
TRUST
Certain members of VOC Sponsors management team were
involved in the formation and initial public offering of MV Oil
Trust (NYSE: MVO) (MVO), a publicly-traded trust
that is similar to VOC Energy Trust. In connection with the
formation of MVO, the sponsor conveyed an 80% term net profits
interest in oil and natural gas properties in the Mid-Continent
region in Kansas and Colorado to MVO in exchange for trust
units, a portion of which were sold by the sponsor in MVOs
initial public offering in January 2007. The terms of the net
profits interest being conveyed in connection with the formation
of VOC Energy Trust are similar to those of the net profits
interest that was conveyed to MVO.
To offset the natural decline in production of the proved
developed wells, the sponsor planned and executed a development
and workover program. The results of this program have mitigated
the decline, with daily production being approximately 2,859 Boe
at the time of the initial public offering (or approximately
2,287 Boe attributable to MVOs 80% net profits interest)
and 2,650 Boe (or approximately 2,120 Boe attributable to
MVOs 80% net profits interest) for the nine months ended
September 30, 2010. As a result of differences in pricing,
wells, costs, development schedule, development expenditures and
regulatory environment, among other things, the historical
results of operations and performance of MVO should not be
relied on as an indicator of how the trust will perform.
From the formation of MVO through December 23, 2010, MVO
distributed approximately $8.98 per MVO trust unit in the
aggregate. As of December 23, 2010, the closing price of
each MVO unit as reported by the New York Stock Exchange was
$36.51. MVO is expected to terminate on the later to occur of
(1) June 30, 2026, or (2) the time when
14.4 MMBoe have been produced and sold from the MVO
underlying properties.
47
CERTAIN
RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
RELATED
PARTY TRANSACTIONS
As of December 31, 2009, the VOC Operators, which includes
Vess Oil, L.D. Drilling, Inc. and Davis Petroleum, Inc.,
operated or operated on a contract basis, approximately 98% of
the total proved reserves attributable to the Underlying
Properties based on PV-10 value, with Vess Oil operating
approximately 90% of the total proved reserves for which VOC
Sponsor is the designated operator and L.D. Drilling Inc.
and Davis Petroleum, Inc. operating approximately 8% of the
total proved reserves. Vess Oil is controlled by J. Michael
Vess, L.D. Drilling Inc. is controlled by L.D. Davis
and Davis Petroleum, Inc. is controlled by both Mr. Vess
and Mr. Davis. Under the terms of the operating arrangement
among VOC Sponsor and Vess Oil, all expenses of Vess Oil
incurred on behalf of VOC Sponsor are paid by VOC Sponsor at the
cost incurred. Below is a summary of the transactions that
occurred between VOC Sponsor and the VOC Operators:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
Year Ended December 31,
|
|
September 30,
|
|
|
2007
|
|
2008
|
|
2009
|
|
2009
|
|
2010
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
Lease operating expenses incurred
|
|
$
|
10,002
|
|
|
$
|
11,734
|
|
|
$
|
10,723
|
|
|
$
|
7,946
|
|
|
$
|
8,377
|
|
Overhead costs included in lease operating expenses incurred
|
|
|
1,146
|
|
|
|
1,253
|
|
|
|
1,401
|
|
|
|
1,039
|
|
|
|
1,132
|
|
Capitalized lease equipment and producing leaseholds cost
incurred
|
|
|
1,882
|
|
|
|
1,926
|
|
|
|
2,094
|
|
|
|
1,132
|
|
|
|
2,863
|
|
Payment of well development costs
|
|
|
2,219
|
|
|
|
2,386
|
|
|
|
2,406
|
|
|
|
1,026
|
|
|
|
6,099
|
|
Payment of management fees
|
|
|
447
|
|
|
|
447
|
|
|
|
447
|
|
|
|
335
|
|
|
|
335
|
|
VOC Sponsor pays the VOC Operators an overhead fee based on a
monthly charge per active operated well to operate substantially
all of the Underlying Properties located in Kansas on behalf of
VOC Sponsor. The fee is adjusted annually and will increase or
decrease each year based on changes in the Overhead Adjustment
Index (OAI) published by the Council of Petroleum
Accountants Society for that year. The operating activities
include various maintenance, engineering, geological, accounting
and administrative functions.
For the Underlying Properties located in Texas, VOC Sponsor
reimburses Vess Texas Partners, LLC (Vess
LLC) for certain corporate administrative and
accounting services arranged by Vess LLC. This reimbursement
amount is adjusted annually and will increase or decrease each
year based on changes in the OAI for that year. Most of the
services for which Vess LLC is reimbursed are performed on
behalf of Vess LLC by Vess Oil. The fee is currently $37,250 per
month.
Vess LLC pays a portion of this $37,250 as an overhead fee to
Vess Oil to operate substantially all of the Underlying
Properties located in Texas on behalf of VOC Sponsor. The
operating activities include various maintenance, engineering,
geological, accounting and administrative functions. The
overhead fee includes (1) a fixed monthly charge of $13,500
per month, (2) reimbursement for certain geological and
engineering services and (3) a monthly charge per active
well brought on production after September 2009, which is
adjusted annually and based on changes in the Overhead
Adjustment Index.
Vess Oil is not contractually obligated to provide the corporate
administrative and accounting services on behalf of VOC Sponsor
or Vess LLC other than with respect to the operation of the
Underlying Properties, and VOC Sponsor and Vess LLC may contract
for the provision of the corporate administrative and accounting
services from other parties at any time. None of the members of
the executive management team are contractually obligated to
continue performing
48
services on behalf of VOC Sponsor, and Vess Oil is not
contractually obligated to make its employees available to
perform such services.
The fees described above are independent of the fees payable by
the trust pursuant to the trust agreement and the Administrative
Services Agreement. See The trust and
Description of the trust agreement Fees and
expenses.
For the nine-months ended September 30, 2010, VOC Sponsor
sold approximately 32% of the oil produced from the Underlying
Properties to MV Purchasing, LLC, (MV Purchasing) an affiliate
of VOC Sponsor. A summary of sales and trade receivables with MV
Purchasing follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended December 31,
|
|
|
September 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
Sales
|
|
$
|
|
|
|
$
|
1,207,358
|
|
|
$
|
13,482,074
|
|
|
$
|
9,176,357
|
|
|
$
|
14,185,601
|
|
Trade Receivables
|
|
$
|
|
|
|
$
|
319,109
|
|
|
$
|
1,359,842
|
|
|
|
|
|
|
$
|
1,410,080
|
|
MV Purchasing began operations on August 1, 2008.
Forty-five days following the closing of the initial public
offering of trust units, VOC Partners, LLC will
(1) purchase, at the initial offering price, trust units
owned by VOC Sponsor and (2) issue a promissory note to VOC
Sponsor having a face amount equal to 90% of the purchase price
for the trust units and a cash payment equal to 10% of the
purchase price for the trust units. This unsecured note that is
fully recourse to VOC Partners, LLC will have a term of ten
years with interest payable at 5% per year.
49
THE
TRUST
The trust is a statutory trust created under the Delaware
Statutory Trust Act in November 2010. The business and
affairs of the trust will be managed by The Bank of New York
Mellon Trust Company, N.A., as trustee. VOC Sponsor has no
ability to manage or influence the operations of the trust. In
addition, Wilmington Trust Company will act as Delaware
trustee of the trust. The Delaware trustee will have only
minimal rights and duties as are necessary to satisfy the
requirements of the Delaware Statutory Trust Act. In
connection with the completion of this offering, VOC Sponsor
will contribute the Net Profits Interest to the trust in
exchange
for newly
issued trust units. VOC Sponsor will make its first payment to
the trust pursuant to the Net Profits Interest on or about
August 15, 2011, which payment will cover the net proceeds
attributable to the Net Profits Interest for the first two
quarters of 2011 consisting of the period from January 1 to
June 30. Subsequent distributions will only cover the net
proceeds attributable to the Net Profits Interest for one
quarter, and, as a result, will be smaller.
The trustee can authorize the trust to borrow money to pay trust
administrative or incidental expenses that exceed cash held by
the trust. The trustee may authorize the trust to borrow from
the trustee as a lender provided the terms of the loan are fair
to the trust unitholders. The trustee may also deposit funds
awaiting distribution in an account with itself, if the interest
paid to the trust at least equals amounts paid by the trustee on
similar deposits, and make other short-term investments with the
funds distributed to the trust. The trustee has no current plans
to authorize the trust to borrow money. VOC Sponsor has also
agreed to post a letter of credit in the amount of
$1 million in favor of the trustee to protect the trustee
against the risk that the trust does not have sufficient cash to
pay its expenses.
The trust will pay the trustee an administrative fee of $150,000
per year. The trust will pay the Delaware trustee a fee of
$2,500 per year. The trust will also incur legal, accounting,
tax and engineering fees, printing costs and other expenses that
are deducted by the trust before distributions are made to trust
unitholders, including the $18,750 administrative services fee
payable quarterly to VOC Sponsor pursuant to the administrative
services agreement described below. The trust will also be
responsible for paying other expenses incurred as a result of
being a publicly traded entity, including costs associated with
annual and quarterly reports to unitholders, tax return and
Form 1099 preparation and distribution, NYSE listing fees,
independent auditor fees and registrar and transfer agent fees.
Total administrative expenses of the trust on an annualized
basis for 2011 are initially expected to be approximately
$900,000, including the administrative services fee payable to
VOC Sponsor and the trustee. In connection with the closing of
this offering, the trust will enter into an administrative
services agreement with VOC Sponsor that obligates the trust,
throughout the term of the trust, to pay to VOC Sponsor each
quarter an administrative services fee for accounting,
bookkeeping and informational services to be performed by VOC
Sponsor on behalf of the trust relating to the Net Profits
Interest. The annual fee, payable in equal quarterly
installments, will total $75,000 in 2011 and will increase by 4%
each year beginning in January 2012. The administrative services
agreement will terminate upon the termination of the Net Profits
Interest unless earlier terminated by mutual agreement of the
trustee and VOC Sponsor.
The Net Profits Interest will terminate on the later to occur of
(1) December 31, 2030, or (2) the time when
9.7 MMBoe have been produced from the Underlying Properties
and sold (which amount is the equivalent of 7.8 MMBoe in
respect of the trusts right to receive 80% of the net
proceeds from the Underlying Properties pursuant to the Net
Profits Interest), and the trust will wind up its affairs and
terminate.
50
PROJECTED
CASH DISTRIBUTIONS
Immediately prior to the closing of this offering, VOC Sponsor
will create the term Net Profits Interest through a conveyance
to the trust of a Net Profits Interest carved from VOC
Sponsors interests in substantially all of its oil and
natural gas properties, which properties are located in Kansas
and Texas. The Net Profits Interest will entitle the trust to
receive 80% of the net proceeds from the sale of production of
oil and natural gas attributable to the Underlying Properties
until the later to occur of (1) December 31, 2030, or
(2) the time when 9.7 MMBoe have been produced from
the Underlying Properties and sold (which amount is the
equivalent of 7.8 MMBoe in respect of the trusts
right to receive 80% of the net proceeds from the Underlying
Properties pursuant to the Net Profits Interest).
The amount of trust revenues and cash distributions to trust
unitholders will depend on, among other things:
|
|
|
|
|
oil sales prices and, to a lesser extent, natural gas sales
prices;
|
|
|
|
the volume of oil and natural gas produced and sold attributable
to the Underlying Properties;
|
|
|
|
the payments made or received by VOC Sponsor pursuant to the
hedge contracts;
|
|
|
|
property and production taxes;
|
|
|
|
development expenses;
|
|
|
|
lease operating expenses; and
|
|
|
|
administrative expenses of the trust.
|
The following table presents a calculation of projected cash
distributions to holders of trust units who own trust units as
of the record date for the distribution for the first quarter of
2011 (assuming, for purposes of the table, that there were
quarterly distributions made for each of the four quarters in
2011) and continue to own those trust units through the
record date for the cash distribution payable with respect to
oil and natural gas production for the last quarter of 2011. The
cash distribution projections for the twelve months ending
December 31, 2011 were prepared by VOC Sponsor on an
accrual of production basis based on the hypothetical
assumptions that are described below and in
Significant assumptions used to prepare the
projected cash distributions. By accrual of production
basis, it is assumed that cash distributions for a quarter
relate to actual production in that quarter. Actual cash
distributions by the trust will be made on a cash basis, and, as
a result, will vary from those presented due to, among other
things, the delay between accruing for sales of production and
VOC Sponsors receiving payment from purchasers of the
production. In addition, for the year ending December 31,
2011, VOC Sponsor will not make its first payment to the trust
pursuant to the Net Profits Interest until on or about
August 15, 2011, which payment will cover the net proceeds
attributable to the Net Profits Interest for the first two
quarters of 2011, less any general and administrative expenses
and reserves of the trust.
VOC Sponsor does not as a matter of course make public
projections as to future sales, earnings or other results.
However, the management of VOC Sponsor has prepared the
projected financial information set forth below to present the
projected cash distributions to the holders of the trust units
based on the estimates and hypothetical assumptions described
below. The accompanying projected financial information was not
prepared with a view toward complying
51
with the published guidelines of the SEC or guidelines
established by the American Institute of Certified Public
Accountants with respect to projected financial information.
In the view of VOC Sponsors management, the accompanying
unaudited projected financial information was prepared on a
reasonable basis and reflects the best currently available
estimates and judgments of VOC Sponsor related to oil and
natural gas production, operating expenses and development
expenditures, based on:
|
|
|
|
|
the oil and natural gas production estimates for the year ending
December 31, 2011 contained in the reserve reports;
|
|
|
|
estimated production and development costs for the year ending
December 31, 2011, contained in the reserve
reports; and
|
|
|
|
projected payments made or received pursuant to the hedge
contracts, if any, for the year ending December 31, 2011
assuming the hypothetical prices used in the following table and
the hedge contracts to be entered into by VOC Sponsor as of the
closing of this offering related to production for 2011.
|
The projected financial information was also based on the
hypothetical assumption that prices for oil and natural gas
remain constant during the twelve months ending
December 31, 2011 and are $
per Bbl of oil and $ per MMBtu of
natural gas (which prices exclude the effects of financial
hedging arrangements). These prices represent average annual
NYMEX futures prices as
of .
These hypothetical prices are then adjusted to take into account
VOC Sponsors estimate of the basis differential (based on
location and quality of the production) between published prices
and the prices actually received by VOC Sponsor. Actual prices
paid for oil and natural gas expected to be produced from the
Underlying Properties in 2011 will likely differ from these
hypothetical prices due to fluctuations in the prices generally
experienced with respect to the production of oil and natural
gas and variations in basis differentials. For example, the
published average monthly closing NYMEX crude oil spot price per
Bbl was $78.10 for the nine months ended September 30,
2010, with the actual monthly closing prices ranging from $71.92
to $86.15 during such period. See Significant Assumptions
used to prepare the projected cash distributions and
Risk factors Prices of oil and natural gas
fluctuate due to a number of factors that are beyond the control
of the trust and VOC Sponsor, and lower prices could reduce
proceeds to the trust and cash distributions to
unitholders.
VOC Sponsor utilized these production estimates, hypothetical
oil and natural gas prices and cost estimates in preparing the
projected financial information. This methodology is consistent
with the requirements of the SEC for estimating oil and natural
gas reserves and discounted present value of future net revenues
attributable to the Net Profits Interest, except that VOC
Sponsor utilized average 2011 NYMEX futures prices rather than
average historical monthly prices for oil and natural gas. The
actual production amounts, commodity prices and costs for 2011
may vary from those VOC Sponsor has projected, and such
variations could be material. Accordingly, the projected
financial information should not be relied upon as being
necessarily indicative of future results. Readers of this
prospectus are cautioned not to place undue reliance on the
projected financial information.
Neither VOC Sponsors independent auditors nor any other
independent accountants have compiled, examined or performed any
procedures with respect to the projected financial information
contained herein, nor have they expressed any opinion or any
other form of assurance on such information or its
achievability, and assume no responsibility for, and disclaim
any association with, the projected financial information.
52
The projections and the estimates and hypothetical assumptions
on which they are based are subject to significant
uncertainties, many of which are beyond the control of VOC
Sponsor or the trust. Actual cash distributions to trust
unitholders, therefore, could vary significantly based upon
events or conditions occurring that are different from the
events or conditions assumed to occur for purposes of these
projections. Cash distributions to trust unitholders will be
particularly sensitive to fluctuations in oil and natural gas
prices. See Risk factors Prices of oil and
natural gas fluctuate due to a number of factors that are beyond
the control of the trust and VOC Sponsor, and lower prices could
reduce proceeds to the trust and cash distributions to
unitholders. As a result of typical production declines
for oil and natural gas properties, production estimates
generally decrease from year to year, and the projected cash
distributions shown in the following table are not necessarily
indicative of distributions for future years. See
Sensitivity of projected cash distributions to
oil and natural gas production and prices below, which
shows projected effects on cash distributions from hypothetical
changes in oil and natural gas production and prices. Because
payments to the trust will be generated by depleting assets and
the trust has a finite life with the production from the
Underlying Properties diminishing over time, a portion of each
distribution will represent a return of your original
investment. See Risk factors The reserves
attributable to the Underlying Properties are depleting assets
and production from those reserves will diminish over time.
Furthermore, the trust is precluded from acquiring other oil and
natural gas properties or net profits interests to replace the
depleting assets and production. Therefore, proceeds to the
trust and cash distributions may decrease over time.
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ending
|
|
|
Projection for Twelve
|
|
|
|
March 31,
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
Months Ending
|
|
|
|
2011
|
|
|
2011
|
|
|
2011
|
|
|
2011
|
|
|
December 31, 2011
|
|
|
|
(Dollars in thousands, except per Bbl, Mcf, MMBtu and per
unit amounts)
|
|
|
Underlying Properties sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales (MBoe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX future prices (1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Natural Gas (per MMBtu)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Assumed realized sales price (2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Natural gas (per Mcf)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Calculation of net proceeds:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross proceeds:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Natural gas sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and development costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Production and property taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Settlement of hedge contracts (payment received) (3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net proceeds
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage allocable to Net Profits Interest
|
|
|
80
|
%
|
|
|
80
|
%
|
|
|
80
|
%
|
|
|
80
|
%
|
|
|
80
|
%
|
Net proceeds to trust from Net Profits Interest
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trust general and administrative expenses (4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash available for distribution by the trust
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash distribution per trust unit
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Average NYMEX futures price for
2011, as reported
on .
For a description of the effect of lower NYMEX prices on
projected cash distributions, please read
Sensitivity of projected cash distributions to oil and natural
gas production and prices.
|
54
|
|
|
(2) |
|
Sales price net of forecasted gravity, quality, transportation,
and marketing costs. For more information about the estimates
and hypothetical assumptions made in preparing the table above,
see Significant assumptions used to prepare
the projected cash distributions. |
|
(3) |
|
Costs will be reduced by hedge payments received by VOC Sponsor
under the hedge contracts. If the hedge payments received by VOC
Sponsor under the hedge contracts exceed costs during a
quarterly period, the ability to use such excess amounts to
offset costs will be deferred, with interest accruing on such
amounts at the prevailing money market rate, until the next
quarterly period when the hedge payments are less than such
costs. |
|
(4) |
|
Total general and administrative expenses of the trust on an
annualized basis for 2011 are expected to be $900,000, which
includes an annual administrative fee to VOC Sponsor in the
amount of $75,000 in 2011, which fee will increase by 4%
annually beginning in January 2012, the annual fee to the
trustees, accounting fees, engineering fees, printing costs and
other expenses properly chargeable to the trust. |
SIGNIFICANT
ASSUMPTIONS USED TO PREPARE THE PROJECTED CASH
DISTRIBUTIONS
Timing of actual distributions. In preparing
the projected cash distributions and sensitivity analysis above,
the revenues and expenses of the trust were calculated based on
the terms of the conveyance creating the trusts Net
Profits Interest. These calculations are described under
Computation of net proceeds Net Profits
Interest, except that amounts for the projection and
previous table above were calculated on an accrual of production
basis rather than the cash basis prescribed by the conveyance.
By accrual of production basis, it is assumed that cash
distributions for a quarter relate to actual production in that
quarter as opposed to cash received in that quarter. As a
result, the proceeds for production for a portion of the three
months ended December 31, 2011, as reflected in the
projection and sensitivity analysis, will actually enter into
the calculation of net proceeds to be received by the trust in
2011 even though the trust will not be paid for such production
until 2012.
Production estimates and development
expenses. Production estimates for 2011 are based
on the reserve reports. Production from the Underlying
Properties for 2011 is estimated to be 771 MBbls of oil and
516 MMcf of natural gas. Net sales for the nine months
ended September 30, 2010 were 618 MBbls of oil and
519 MMcf of natural gas. Net sales for the year ending
December 31, 2009 were 732 MBbls of oil and
693 MMcf of natural gas. The projected increase of
estimated production for 2011 is primarily the result of
approximately $2.1 million of development expenditures on
the Underlying Properties that either have been or are planned
to be incurred by VOC Sponsor for well workover and other
development activities during the second half of 2010. In
addition, VOC Sponsor expects to incur approximately
$8.0 million of development expenditures during 2011 to
further increase production from the Underlying Properties in
2011. Although VOC Sponsor expects annual production from the
Underlying Properties to decline at an average annual rate of
6.7% over the next 20 years, VOC Sponsor expects the actual
annual decline rate to be smaller during the beginning of that
period and to increase over the course of that period. The
expected increase in the annual decline rate over the course of
this 20-year
period is primarily a result of the assumption that no
additional development drilling or other development
expenditures will be made after 2014 on the Underlying
Properties.
Oil and natural gas prices. Hypothetical oil
and natural gas prices assumed in the projected cash
distribution table are based on average 2011 NYMEX futures
prices for oil and natural gas as
of .
Published NYMEX benchmark prices for crude oil are based upon an
assumed light, sweet crude oil of a particular gravity that is
stored in Cushing, Oklahoma while published NYMEX benchmark
prices for natural gas are based upon delivery at the Henry Hub
in Louisiana.
55
These prices differ from the average or actual price received
for production attributable to the Underlying Properties.
Differentials between published oil and natural gas prices and
the prices actually received for the oil and natural gas
production may vary significantly due to market conditions,
transportation costs, quality of production and other factors.
In the above table, $ per barrel
is deducted from the average 2011 NYMEX futures price for crude
oil to reflect these differentials. This deduction is based on
VOC Sponsors estimate of the average difference between
the NYMEX published price of crude oil and the price to be
received by VOC Sponsor for production attributable to the
Underlying Properties during 2011. Projected average oil prices
appearing in this prospectus have been adjusted for these
differentials.
In the above table, $
per Mcf is the average 2011 NYMEX price adjustment for natural
gas in 2011 to reflect these differentials. This adjustment is
based on VOC Sponsors estimate of the average difference
between the NYMEX published price of natural gas and the price
to be received by VOC Sponsor for production attributable to the
Underlying Properties during 2011. Projected average natural gas
prices appearing in this prospectus have been adjusted for these
differentials.
The differentials to published oil and natural gas prices
applied in the above projected cash distribution estimate are
based upon an analysis by VOC Sponsor of the historic price
differentials for production from the Underlying Properties with
consideration given to gravity, quality and transportation and
marketing costs that may affect these differentials in 2011.
There is no assurance that these assumed differentials will
occur in 2011.
When oil and natural gas prices decline, the operators of the
properties comprising the Underlying Properties may elect to
reduce or completely suspend production. No adjustments have
been made to estimated 2011 production to reflect potential
reductions or suspensions of production.
Settlement of Hedge Contracts. VOC Sponsor has
entered into fixed price swap contracts for 2011 with respect to
159,864 Bbls of oil expected to be produced from the
Underlying Properties at a weighted average price per Bbl of
$94.90 that hedge approximately 22% of the expected production
from the proved developed producing reserves attributable to the
Underlying Properties for 2011 in the reserve reports. The crude
oil swap contracts will settle based on the average of the
settlement price for each commodity business day in the contract
month. In a swap transaction, the counterparty is required to
make a payment to VOC Sponsor for the difference between the
fixed price and the settlement price if the settlement price is
below the fixed price. VOC Sponsor is required to make a payment
to the counterparty for the difference between the fixed price
and the settlement price if the settlement price is above the
fixed price.
Costs. For 2011, VOC Sponsor estimates lease
operating expenses to be
$ million, production and
property taxes to be
$ million and development
expenses to be $ million. For
the nine months ended September 30, 2010, lease operating
expenses were $10.0 million, production and property taxes
were $2.9 million and development expenses were
$9.0 million. For a description of production expenses and
development costs, see Computation of net
proceeds Net profits interest. VOC Sponsor
expects its costs in 2011 to be substantially the same as its
expected costs in 2010 after giving effect to development
projects expected to be undertaken during the third and fourth
quarters of 2010.
Administrative expense. The trust will be
responsible for paying all legal, accounting, tax advisory,
engineering and stock exchange fees, printing costs and other
administrative and
out-of-pocket
expenses incurred by or at the direction of the trustee or the
Delaware trustee. The
56
trust will also be responsible for paying other expenses
incurred as a result of being a publicly traded entity,
including costs associated with annual and quarterly reports to
unitholders, preparation of tax information material and
distribution, independent auditor fees and registrar and
transfer agent fees. These trust administrative expenses are
anticipated to aggregate approximately $900,000 for 2011.
Administrative expenses for subsequent years could be greater or
less depending on future events that cannot be predicted.
Included in the $900,000 annual estimate is an annual
administrative fee of $150,000 for the trustee and an annual
administrative fee of $2,500 for the Delaware trustee as well as
an annual administrative fee payable to VOC Sponsor, which fee
will total $75,000 in 2011 and will increase by 4% each year
beginning in January 2012. The trust will pay, out of the first
cash payment received by the trust, the trustees and
Delaware trustees legal expenses incurred in forming the
trust as well as the Delaware trustees acceptance fee in
the amount of $4,000. These costs will be deducted by the trust
before distributions are made to trust unitholders. See
The trust.
SENSITIVITY
OF PROJECTED CASH DISTRIBUTIONS TO OIL AND NATURAL GAS
PRODUCTION AND PRICES
The amount of revenues of the trust and cash distributions to
the trust unitholders will be directly dependent on the sales
price for oil and natural gas production sold from the
Underlying Properties, the volumes of oil and natural gas
produced attributable to the Underlying Properties, payments
made or received under the hedge contracts and variations in
lease operating expenses, production and property taxes and
development costs.
The table and discussion below sets forth sensitivity analyses
of annual cash distributions per trust unit for the twelve
months ending December 31, 2011, on an accrual basis of
production, on the assumption that a trust unitholder purchased
a trust unit on January 1, 2011 and held such trust unit
until the quarterly record date for distributions made with
respect to oil and natural gas production in the last quarter of
2011, based upon (1) the assumption that a total
of
trust units are issued and outstanding after the closing of the
offering made hereby; (2) various realizations of the
production levels estimated in the summary reserve report;
(3) the hypothetical commodity prices based upon NYMEX
futures prices; (4) the impact of the hedge contracts
entered into by VOC Sponsor that relate to production from the
Underlying Properties; and (5) other assumptions described
below under Significant assumptions used to
prepare the projected cash distributions. The hypothetical
commodity prices of oil and natural gas production shown have
been chosen solely for illustrative purposes. For a description
of the effect of calculating annual cash distributions on an
accrual basis rather than on a cash basis as prescribed in the
conveyance of the Net Profits Interest, see
Significant assumptions used to prepare the
projected cash distributions Timing of actual
distributions.
The table below is not a projection or forecast of the actual
or estimated results from an investment in the trust units. The
purpose of the table below is to illustrate the sensitivity of
cash distributions to changes in oil and natural gas production
levels and oil and natural gas pricing (giving effect to the
hedge contracts that will be in place in 2011). There is no
assurance that the hypothetical assumptions described below will
actually occur or that production levels or NYMEX futures prices
will not change by amounts different from those shown in the
tables.
57
Sensitivity
of Total 2011 Projected Annual Cash Distribution Per
Trust Unit
to Changes in Estimated Oil and Natural Gas Production and NYMEX
Futures Pricing
|
|
|
(1) |
|
Estimated oil and natural gas production is based on the reserve
reports, and the sensitivity analysis assumes there will be no
variation by location and that oil and natural gas production
will continue to represent the same percentage of total
production as estimated for 2011 in the reserve report. |
58
THE
UNDERLYING PROPERTIES
The Underlying Properties consist of VOC Sponsors net
interests in substantially all of its oil and natural gas
properties after deduction of all royalties and other burdens on
production thereon as of the date of conveyance of the Net
Profits Interest to the trust. As of December 31, 2009,
these oil and natural gas properties consisted of approximately
892 gross (550.2 net) producing oil and natural gas wells
in 193 fields in VOC Sponsors two operating areas, Kansas
and Texas. During the nine months ended September 30, 2010,
average net production from the Underlying Properties was
approximately 2,583 Boe per day (or 2,066 Boe per day
attributable to the trust) comprised of approximately 88% oil
and 12% natural gas. As of December 31, 2009, proved
reserves attributable to the Underlying Properties, as estimated
in the reserve reports, were approximately 13.0 MMBoe with
a PV-10
value of $178.7 million.
VOC Sponsors interests in the properties comprising the
Underlying Properties require VOC Sponsor to bear its
proportionate share along with the other working interest owners
of the costs of development and operation of such properties.
The properties comprising the Underlying Properties are burdened
by non-working interests owned by third parties consisting
primarily of overriding royalty and royalty interests retained
by the owners of the land subject to the working interests.
These landowners royalty interests typically entitle the
landowner to receive 12.5% of the revenue derived from oil and
natural gas production resulting from wells drilled on the
landowners land, without any deduction for drilling costs
or other costs related to production of oil and natural gas. A
working interest percentage represents a working interest
owners proportionate ownership interest in a property in
relation to all other working interest owners in that property,
whereas a net revenue interest percentage is a working interest
owners percentage of production after reducing such
percentage by the percentage of burdens on such production such
as royalties and overriding royalties. As of December 31,
2009, VOC Sponsor held average working interests of 74.7% and
66.8% in the Underlying Properties located in the States of
Kansas and Texas, respectively. As of December 31, 2009,
the VOC Operators were the operators or contract operators of
98% of the proved reserves attributable to the Underlying
Properties, based on
PV-10 value,
and VOC Sponsor held an average net revenue interest of 62.5%
and 55.1% for the Underlying Properties located in Kansas and
Texas, respectively.
Based on the reserve reports, the Net Profits Interest would
entitle the trust to receive net proceeds from the sale of
production of not less than 7.8 MMBoe of proved reserves
attributable to the Underlying Properties expected to be
produced over the term of the trust. The trust is entitled to
receive 80% of the net proceeds from the sale of production of
oil and natural gas attributable to the Underlying Properties
that are produced during the term of the trust, whereas total
reserves as reflected on the summary reserve reports and
attributable to the Underlying Properties include all reserves
expected to be economically produced during the economic life of
the properties.
VOC Sponsor has agreed to use commercially reasonable efforts to
cause the operators of the Underlying Properties to operate
these properties as would a reasonably prudent operator acting
with respect to its own properties (without regard to the
existence of the Net Profit Interest). In addition, after giving
effect to the conveyance of the Net Profits Interest to the
trust, VOC Sponsors interest in the Underlying Properties
entitles it to 20% of the net proceeds from the sale of
production of oil and natural gas attributable to VOC
Sponsors interest in the Underlying Properties during the
term of the trust, and 100% thereafter. VOC Sponsor believes
that its retained interests in the Underlying Properties
combined with VOC Partners, LLCs ownership of trust units
representing a 34.8% beneficial interest in the trust, which
collectively entitle VOC Sponsor and VOC Partners, LLC to
receive approximately 48% of the net proceeds from the
Underlying Properties, will provide sufficient incentive to
operate and develop the oil and
59
natural gas properties comprising the Underlying Properties in
an efficient and cost-effective manner.
In general, the producing wells included in the Underlying
Properties have stable production profiles and their production
is long-lived, often with total projected economic lives in
excess of 50 years. Based on the reserve report, annual
production from the Underlying Properties is expected to decline
at an average annual rate of 6.7% over the next 20 years
assuming no additional development drilling or other development
expenditures are made on the Underlying Properties after 2014.
VOC Sponsor expects total development expenditures for the
Underlying Properties during the next five years will be
approximately $25.4 million, which it expects will
partially offset the natural decline in production otherwise
expected to occur with respect to the Underlying Properties as
described in more detail below.
SELECTED
HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL AND OPERATING DATA
OF THE UNDERLYING PROPERTIES
The following table sets forth revenues, direct operating
expenses and the excess of revenues over direct operating
expenses relating to the Predecessor Underlying Properties and
the Acquired Underlying Properties for the three years in the
period ended December 31, 2009 and for the nine-month
periods ended September 30, 2009 and 2010 derived from the
audited and unaudited statements of historical revenues and
direct operating expenses of each of the Predecessor Underlying
Properties and the Acquired Underlying Properties included
elsewhere in this prospectus. The unaudited statements were
prepared on a basis consistent with the audited statements and,
in the opinion of VOC Sponsor, include all adjustments
(consisting only of normal recurring adjustments) necessary to
present fairly the revenues, direct operating expenses and the
excess of revenues over direct operating expenses relating to
the Predecessor Underlying Properties and the Acquired
Underlying Properties for the periods presented.
The following table also sets forth revenues, direct operating
expenses and the excess of revenues over direct operating
expenses relating to the Predecessor Underlying Properties after
giving pro forma effect to the acquisition of the Acquired
Underlying Properties for the year ended December 31, 2009
and for the nine months ended September 30, 2010. The
information included in this table is derived from the unaudited
pro forma statements of historical revenues and direct operating
expenses of the Predecessor Underlying Properties included in
this prospectus beginning on
page F-18.
The pro forma adjustments have been prepared as if the
acquisition of the Acquired Underlying Properties by Predecessor
had taken place (1) on September 30, 2010, in the case
of the pro forma balance sheet information, and (2) as of
60
January 1, 2009, in the case of the pro forma statement of
earnings information for the year ended December 31, 2009,
and for the nine months ended September 30, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended December 31,
|
|
|
September 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
Predecessor Underlying Properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
26,040
|
|
|
$
|
36,632
|
|
|
$
|
22,758
|
|
|
$
|
15,020
|
|
|
$
|
27,384
|
|
Natural gas sales
|
|
|
2,495
|
|
|
|
3,350
|
|
|
|
1,511
|
|
|
|
1,045
|
|
|
|
1,857
|
|
Hedge and other derivative activity
|
|
|
(7,245
|
)
|
|
|
(7,785
|
)
|
|
|
1,477
|
|
|
|
1,880
|
|
|
|
(151
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
21,290
|
|
|
|
32,197
|
|
|
|
25,746
|
|
|
|
17,945
|
|
|
|
29,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bad debt expense (recovery)
|
|
|
|
|
|
|
1,727
|
|
|
|
(719
|
)
|
|
|
(719
|
)
|
|
|
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
6,586
|
|
|
|
7,667
|
|
|
|
6,788
|
|
|
|
5,053
|
|
|
|
5,229
|
|
Production and property taxes
|
|
|
1,874
|
|
|
|
2,532
|
|
|
|
1,646
|
|
|
|
1,258
|
|
|
|
1,919
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
8,460
|
|
|
|
10,199
|
|
|
|
8,434
|
|
|
|
6,311
|
|
|
|
7,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
12,830
|
|
|
$
|
20,271
|
|
|
$
|
18,031
|
|
|
$
|
12,353
|
|
|
$
|
21,942
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquired Underlying Properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
21,328
|
|
|
$
|
29,298
|
|
|
$
|
17,602
|
|
|
$
|
12,158
|
|
|
$
|
17,298
|
|
Natural gas sales
|
|
|
1,904
|
|
|
|
2,248
|
|
|
|
781
|
|
|
|
582
|
|
|
|
683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
23,232
|
|
|
|
31,545
|
|
|
|
18,383
|
|
|
|
12,740
|
|
|
|
17,981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bad debt expense
|
|
|
|
|
|
|
2,166
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
5,412
|
|
|
|
6,046
|
|
|
|
5,969
|
|
|
|
4,396
|
|
|
|
4,690
|
|
Production and property taxes
|
|
|
1,231
|
|
|
|
1,614
|
|
|
|
1,170
|
|
|
|
814
|
|
|
|
950
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
6,643
|
|
|
|
7,660
|
|
|
|
7,139
|
|
|
|
5,210
|
|
|
|
5,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
16,589
|
|
|
$
|
21,719
|
|
|
$
|
11,244
|
|
|
$
|
7,530
|
|
|
$
|
12,341
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended December 31,
|
|
|
September 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
Predecessor Pro Forma (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
|
|
|
|
|
|
|
|
$
|
40,360
|
|
|
|
|
|
|
$
|
44,682
|
|
Natural gas sales
|
|
|
|
|
|
|
|
|
|
|
2,292
|
|
|
|
|
|
|
|
2,540
|
|
Hedge and other derivative activity
|
|
|
|
|
|
|
|
|
|
|
1,477
|
|
|
|
|
|
|
|
(151
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
44,129
|
|
|
|
|
|
|
|
47,071
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bad debt recovery
|
|
|
|
|
|
|
|
|
|
|
(719
|
)
|
|
|
|
|
|
|
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
|
|
|
|
|
|
|
|
12,757
|
|
|
|
|
|
|
|
9,919
|
|
Production and property taxes
|
|
|
|
|
|
|
|
|
|
|
2,816
|
|
|
|
|
|
|
|
2,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
15,573
|
|
|
|
|
|
|
|
12,788
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
|
|
|
|
|
|
|
|
$
|
29,275
|
|
|
|
|
|
|
$
|
34,283
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table provides oil and natural gas sales volumes,
average sales prices and capital expenditures relating to the
Underlying Properties for the three years in the period ended
December 31, 2009, and for the nine-month periods ended
September 30, 2009 and 2010. Average sales prices do not
include the effect of hedge activity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended December 31,
|
|
|
September 30,
|
|
Underlying Properties
(1)
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
705
|
|
|
|
704
|
|
|
|
732
|
|
|
|
543
|
|
|
|
618
|
|
Natural gas (MMcf)
|
|
|
738
|
|
|
|
750
|
|
|
|
693
|
|
|
|
525
|
|
|
|
519
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales (MBoe)
|
|
|
828
|
|
|
|
829
|
|
|
|
847
|
|
|
|
631
|
|
|
|
705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
67.15
|
|
|
$
|
93.67
|
|
|
$
|
55.16
|
|
|
$
|
50.01
|
|
|
$
|
72.25
|
|
Natural gas (per Mcf)
|
|
$
|
5.96
|
|
|
$
|
7.46
|
|
|
$
|
3.31
|
|
|
$
|
3.10
|
|
|
$
|
4.89
|
|
Capital expenditures (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
$
|
4,463
|
|
|
$
|
7,899
|
|
|
$
|
4,134
|
|
|
$
|
1,981
|
|
|
$
|
2,884
|
|
Well development
|
|
|
2,420
|
|
|
|
2,499
|
|
|
|
2,407
|
|
|
|
1,027
|
|
|
|
6,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
6,882
|
|
|
$
|
10,398
|
|
|
$
|
6,541
|
|
|
$
|
3,008
|
|
|
$
|
8,983
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The operating data below includes
the effect of the Acquired Underlying Properties for all periods
presented.
|
62
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended December 31,
|
|
|
September 30,
|
|
Predecessor Underlying
Properties
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
387
|
|
|
|
389
|
|
|
|
407
|
|
|
|
298
|
|
|
|
374
|
|
Natural gas (MMcf)
|
|
|
391
|
|
|
|
426
|
|
|
|
415
|
|
|
|
311
|
|
|
|
339
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
452
|
|
|
|
460
|
|
|
|
477
|
|
|
|
350
|
|
|
|
431
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
67.31
|
|
|
$
|
94.11
|
|
|
$
|
55.86
|
|
|
$
|
50.37
|
|
|
$
|
73.15
|
|
Natural gas (per Mcf)
|
|
$
|
6.39
|
|
|
$
|
7.86
|
|
|
$
|
3.64
|
|
|
$
|
3.36
|
|
|
$
|
5.47
|
|
Capital expenditures (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
$
|
3,523
|
|
|
$
|
6,715
|
|
|
$
|
2,369
|
|
|
$
|
1,027
|
|
|
$
|
2,328
|
|
Well development
|
|
|
1,603
|
|
|
|
1,063
|
|
|
|
1,955
|
|
|
|
747
|
|
|
|
5,638
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,126
|
|
|
$
|
7,778
|
|
|
$
|
4,324
|
|
|
$
|
1,774
|
|
|
$
|
7,966
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended December 31,
|
|
|
September 30,
|
|
Acquired Underlying
Properties
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
(Unaudited)
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
319
|
|
|
|
315
|
|
|
|
324
|
|
|
|
245
|
|
|
|
244
|
|
Natural gas (MMcf)
|
|
|
347
|
|
|
|
324
|
|
|
|
278
|
|
|
|
214
|
|
|
|
180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MBoe)
|
|
|
376
|
|
|
|
369
|
|
|
|
371
|
|
|
|
281
|
|
|
|
274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
66.96
|
|
|
$
|
93.12
|
|
|
$
|
54.27
|
|
|
$
|
49.58
|
|
|
$
|
70.85
|
|
Natural gas (per Mcf)
|
|
$
|
5.49
|
|
|
$
|
6.94
|
|
|
$
|
2.81
|
|
|
$
|
2.72
|
|
|
$
|
3.80
|
|
Capital expenditures (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
$
|
940
|
|
|
$
|
1,184
|
|
|
$
|
1,765
|
|
|
$
|
954
|
|
|
$
|
556
|
|
Well development
|
|
|
817
|
|
|
|
1,436
|
|
|
|
452
|
|
|
|
280
|
|
|
|
461
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,757
|
|
|
$
|
2,620
|
|
|
$
|
2,217
|
|
|
$
|
1,234
|
|
|
$
|
1,017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DISCUSSION
AND ANALYSIS OF HISTORICAL RESULTS OF THE UNDERLYING
PROPERTIES
Predecessor
Underlying Properties
Comparison
of Results of the Predecessor Underlying Properties for the Nine
Months Ended September 30, 2010 and 2009
Excess of revenues over direct operating expenses for the
Predecessor Underlying Properties was $21.9 million for the
nine months ended September 30, 2010, compared to
$12.4 million for the nine months ended September 30,
2009. The increase was primarily a result of increases in
63
oil production and in the average price received for the oil and
natural gas sold. This was partially offset by an increase in
direct operating expenses and an increase in hedge expense.
Revenues. Revenues from oil and natural gas sales
increased $13.2 million between the periods. This increase
in revenues was primarily the result of an increase in the
average price received for crude oil sold from $50.37 per Bbl
for the nine months ended September 30, 2009 to $73.15 per
Bbl for the nine months ended September 30, 2010 and a
76.1 MBbl increase in oil volumes sold. The increase in
revenues was also the result of an increase in the average price
received for natural gas sold from $3.36 per Mcf for the nine
months ended September 30, 2009 to $5.47 per Mcf for the
nine months ended September 30, 2010, and a 28.2 MMcf
increase in natural gas volumes sold.
Hedge activity. Hedge activity income was
$1.9 million for the nine months ended September 30,
2009 compared to hedge activity expense of $0.2 million for
the nine months ended September 30, 2010. This decrease in
income and increase in expense was due to an increase in
realized hedge losses for the period and the recording of the
change in market value of some of the hedges to the income
statement.
The increase in hedge expense was due to the higher average
NYMEX price per Bbl of crude oil for the first nine months of
2010 of $77.65 compared to $57.00 for the first nine months of
2009. The weighted average settlement price of hedges for the
first nine months of 2010 was $73.06 compared to $68.85 for the
first nine months of 2009.
Bad debt expense (recovery). Bad debt recovery was
$0.7 million for the nine months ended September 30,
2009 reflecting the reversal of the bad debt expense recorded in
2008 with respect to the Texas Underlying Properties as
described below. There was no bad debt expense or recovery
during the nine months ended September 30, 2010.
As publicly reported on July 22, 2008, the revenue
intermediary/crude oil purchaser (Eaglwing L.P.) and its parent
(SemGroup, L.P.) filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code.
During this process, the monies that had been transferred to the
revenue intermediary by certain of Predecessors oil and
gas purchasers for distribution to Predecessor and other working
interest, royalty interest and overriding royalty interest
owners were erroneously retained by the revenue intermediary.
Vess Oil, as primary operator of Predecessors oil and gas
leases, filed suit to recover these funds which were estimated
to be $1.4 million for Predecessors ownership of the
Texas Underlying Properties. In addition, Vess Oil filed a proof
of claim for a statutory lien claim with the bankruptcy court on
behalf of the working interest owners (inclusive of Predecessor
interests), overriding royalty owners and royalty owners. In
2008, as there was no assurance as to the dollar amount, if any,
that would be recovered or the timing of such recovery, an
allowance for doubtful accounts of $0.7, million or 50% of the
total estimated amount owed from Eaglwing, L.P. to Predecessor
for the Texas Underlying Properties, was established as of
December 31, 2008. In addition, an allowance was set up for
the oil purchased from the Kansas Underlying Properties in the
amount of $1.0 million which represents approximately 87%
of June 2008 sales made to Eaglwing, L.P.
Prices. The average price received for the crude oil sold
increased primarily as a result of an increase in the oil price
index on which the sales prices for a majority of the oil
production were based. The average price for natural gas sold
increased as a result of an increase in the natural gas price
index on which the sales prices for a majority of the natural
gas production were based.
Volumes. The increase in overall production sales volumes
during the nine months ended September 30, 2010 compared to
the nine months ended September 30, 2009 is primarily
attributable to the drilling of horizontal wells in the Texas
Underlying Properties during the last
64
quarter of 2009 and the first nine months of 2010. One well was
drilled in the fourth quarter of 2009 and four were drilled in
the first nine months of 2010.
Lease operating expenses. Lease operating expenses
increased from $5.1 million for the nine months ended
September 30, 2009 to $5.2 million for the nine months
ended September 30, 2010. This increase was primarily a
result of an increase in general operating expenses and
increased costs due to additional wells being added which was
partially offset by the cost of electronification of wells in
the Texas Underlying Properties. The VOC Operators are replacing
the gas pumping motors in the Texas Underlying Properties with
electronic motors which can be shut off and restarted during the
day as needed. This process also reduces wear on the moving
parts of the well thereby reducing repairs and maintenance costs.
Production and property taxes. Production and property
taxes increased $0.7 million as a result of the increases
in the price of crude oil and in revenues from oil and natural
gas sales, on which these taxes are based.
Comparison
of Results of the Predecessor Underlying Properties for the
Years Ended December 31, 2009 and 2008
Excess of revenues over direct operating expenses for the
Predecessor Underlying Properties was $18.0 million for the
year ended December 31, 2009, compared to
$20.3 million for the year ended December 31, 2008.
The decrease was primarily a result of a decrease in the average
price received for the oil and natural gas sold. This was
partially offset by an increase in production and a decrease in
direct operating expenses.
Revenues. Revenues from oil and natural gas sales
decreased $15.7 million between the periods. This decrease
in revenues was primarily the result of a decrease in the
average price received for crude oil sold from $94.11 per Bbl
for the year ended December 31, 2008 to $55.88 per Bbl for
the year ended December 31, 2009, partially offset by an
18.1 MBbl increase in oil volumes sold. The decrease in
revenues was also the result of a decrease in the average price
received for natural gas sold from $7.86 per Mcf for the year
ended December 31, 2008 to $3.64 per Mcf for the year ended
December 31, 2009, and an 11.6 MMcf decrease in
natural gas volumes sold.
Bad debt expense (recovery). Bad debt expense was
$1.7 million for the year ended December 31, 2008 and
bad debt recovery was $0.7 million for the year ended
December 31, 2009. During the year ended September 30,
2009, recovery was made of the $1.4 million due for the
Texas Underlying Properties. As a result of the recovery, VOC
Sponsor recorded bad debt recovery of $0.7 million, which
reverses the bad debt expense which was recorded for the Texas
properties in 2008.
As publicly reported on July 22, 2008, the revenue
intermediary/crude oil purchaser (Eaglwing L.P.) and its parent
(SemGroup, L.P.) filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code.
During this process, the monies that had been transferred to the
revenue intermediary by certain of Predecessors oil and
gas purchasers for distribution to Predecessor and other working
interest, royalty interest and overriding royalty interest
owners was erroneously retained by the revenue intermediary.
Vess Oil, as primary operator of Predecessors oil and gas
leases, filed suit to recover these funds which were estimated
to be $1.4 million for Predecessors ownership of the
Texas properties. In addition, Vess Oil filed a proof of claim
for a statutory lien claim with the bankruptcy court on behalf
of the working interest owners (inclusive of Predecessor
interests), overriding royalty owners and royalty owners. In
2008, as there was no assurance as to the dollar amount, if any,
that would be recovered or the timing of such recovery, an
allowance for doubtful accounts of $0.7 million, or
65
50% of the total estimated amount owed from Eaglwing, L.P. to
Predecessor for the Texas Underlying Properties was established
as of December 31, 2008. In addition, an allowance was set
up for the oil purchased from the Kansas Underlying Properties
in the amount of $1.0 million which represents
approximately 87% of June 2008 sales made to Eaglwing, L.P.
Hedge activity. Hedge activity expense was
$7.8 million for the year ended December 31, 2008
compared to hedge activity income of $1.5 million for the
year ended December 31, 2009. This change was due primarily
to the lower average NYMEX settlement price for the year ended
December 31, 2009 of $61.80 compared to $99.65 for the year
ended December 31, 2008. The weighted average hedge price
for 2009 was $68.85 compared to $70.02 for 2008.
Prices. The average price received for crude oil and
natural gas sold decreased primarily as a result of a decrease
in the oil price and natural gas price indices on which the
sales prices for a majority of the production were based.
Volumes. The increase in oil and natural gas sales
volumes was primarily attributable to the acquisition of various
oil and gas working interests during August 2008.
Production during 2008 reflects 4 months production from
the purchase and production during 2009 includes 12 months
production.
Lease operating expenses. Lease operating expenses
decreased from $7.7 million for the year ended
December 31, 2008 to $6.8 million for the year ended
December 31, 2009. This decrease was the result of the
decline in oil prices and the electronification of wells in the
Texas properties.
Production and property taxes. Production and property
taxes decreased $0.9 million as a result of the decrease in
revenues from oil and natural gas sales and decreased property
value on which these taxes are based.
Comparison
of Results of the Predecessor Underlying Properties for the
Years Ended December 31, 2008 and 2007
Excess of revenues over direct operating expenses for the
Predecessor Underlying Properties was $20.3 million for the
year ended December 31, 2008, compared to
$12.8 million for the year ended December 31, 2007.
The increase was primarily a result of an increase in the
average price received for the oil and natural gas sold. This
was partially offset by an increase in direct operating expenses.
Revenues. Revenues from oil and natural gas sales
increased $11.4 million between these periods. This
increase in revenues was primarily the result of an increase in
the average price received for crude oil sold from $67.31 per
Bbl for the year ended December 31, 2007 to $94.11 per Bbl
for the year ended December 31, 2008, and a 2.4 MBbl
increase in oil volumes sold. The increase in revenues was also
the result of an increase in the average price received for
natural gas sold from $6.39 per Mcf for the year ended
December 31, 2007 to $7.86 per Mcf for the year ended
December 31, 2008, and a 35.7 MMcf increase in natural
gas volumes sold.
Prices. The average price received for crude oil and
natural gas sold increased primarily as a result of an increase
in the oil price and natural gas price indices on which the
sales prices for a majority of the production were based.
Hedge activity. Hedge activity expense increased from
$7.2 million for the year ended December 31, 2007 to
$7.8 million for the year ended December 31, 2008.
This increase was due primarily to the higher average NYMEX
settle price for the year ended December 31, 2008 of
66
$99.65 compared to $72.34 for the year ended December 31,
2007. The weighted average hedge price for 2008 was $70.02
compared to $52.27 for 2007.
Bad debt expense (recovery). Bad debt expense was
$1.7 million for the year ended December 31, 2008.
During the year ended December 31, 2007 there was no bad
debt expense or recovery.
As publicly reported on July 22, 2008, the revenue
intermediary/crude oil purchaser (Eaglwing L.P.) and its parent
(SemGroup, L.P.) filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code.
During this process, the monies that had been transferred to the
revenue intermediary by certain of Predecessors oil and
gas purchasers for distribution to Predecessor and other working
interest, royalty interest and overriding royalty interest
owners was erroneously retained by the revenue intermediary.
Vess Oil, as primary operator of Predecessors oil and gas
leases, filed suit to recover these funds which were estimated
to be $1.4 million for Predecessors ownership of the
Texas Underlying Properties. In addition, Vess Oil Corporation
filed a proof of claim for a statutory lien claim with the
bankruptcy court on behalf of the working interest owners
(inclusive of Predecessor interests), overriding royalty owners
and royalty owners. In 2008, as there was no assurance as to the
dollar amount, if any, that would be recovered or the timing of
such recovery, an allowance for doubtful accounts of
$0.7 million, or 50% of the total estimated amount owed
from Eaglwing, L.P. to Predecessor for the Texas Properties was
established as of December 31, 2008. In addition, an
allowance was set up for the oil purchased from the Kansas
Properties in the amount of $1.0 million which represents
approximately 87% of June 2008 sales made to Eaglwing, L.P.
Volumes. The increase in oil and natural gas sales
volumes was primarily attributable to the acquisition of various
oil and gas working interests during August 2008. This increase
was partially offset by the natural decline of proved producing
volumes.
Lease operating expenses. Lease operating expenses
increased from $6.6 million for the year ended
December 31, 2007 to $7.7 million for the year ended
December 31, 2008. This increase was primarily a result of
general inflation in Predecessors primary vendor costs and
the increased costs associated with the acquisition of various
oil and gas working interests during August 2008.
Production and property taxes. Production and property
taxes increased $0.7 million as a result of the increases
in the price of crude oil and in revenues from oil and natural
gas sales, on which these taxes are based.
Acquired
Underlying Properties
Comparison
of Results of the Acquired Underlying Properties for the Nine
Months Ended September 30, 2010 and 2009
Excess of revenues over direct operating expenses for the
Acquired Underlying Properties was $12.3 million for the
nine months ended September 30, 2010, compared to
$7.5 million for the nine months ended September 30,
2009. The increase was primarily a result of an increase in the
average price received for the oil and natural gas sold. This
was partially offset by a decrease in oil and natural gas
volumes and an increase in direct operating expenses.
Revenues. Revenues from oil and natural gas sales
increased $5.2 million between the periods. This increase
in revenues was primarily the result of an increase in the
average price received for crude oil sold from $49.58 per Bbl
for the nine months ended September 30, 2009 to $70.85 per
Bbl for the nine months ended September 30, 2010, partially
offset by a 1.1 MBbl
67
decrease in oil volumes sold. The increase in revenues was also
the result of an increase in the average price received for
natural gas sold from $2.72 per Mcf for the nine months ended
September 30, 2009 to $3.80 per Mcf for the nine months
ended September 30, 2010, partially offset by a
34.1 MMcf decrease in natural gas volumes sold.
Prices. The average price received for the crude oil sold
increased primarily as a result of an increase in the oil price
index on which the sales prices for a majority of the oil
production were based. The average price for natural gas sold
increased as a result of an increase in the natural gas price
index on which the sales prices for a majority of the natural
gas production were based.
Volumes. The decrease in overall production sales volumes
during the nine months ended September 30, 2010 compared to
the nine months ended September 30, 2009 is primarily
attributable to the natural decline of the producing properties.
Lease operating expenses. Lease operating expenses
increased from $4.4 million for the nine months ended
September 30, 2009 to $4.7 million for the nine months
ended September 30, 2010. This increase was primarily a
result of an increase in general operating expenses.
Production and property taxes. Production and property
taxes increased $0.1 million as a result of the increases
in the price of crude oil and in revenues from oil and natural
gas sales, on which these taxes are based.
Comparison
of Results of the Acquired Underlying Properties for the Years
Ended December 31, 2009 and 2008
Excess of revenues over direct operating expenses for the
Acquired Underlying Properties was $11.2 million for the
year ended December 31, 2009, compared to
$21.7 million for the year ended December 31, 2008.
The decrease was primarily a result of a decrease in the average
price received for the oil and natural gas sold. This was
partially offset by an increase in production and a decrease in
direct operating expenses.
Revenues. Revenues from oil and natural gas sales
decreased $13.2 million between the periods. This decrease
in revenues was primarily the result of a decrease in the
average price received for crude oil sold from $93.12 per Bbl
for the year ended December 31, 2008 to $54.27 per Bbl for
the year ended December 31, 2009, partially offset by a
9.7 MBbl increase in oil volumes sold. The decrease in
revenues was also the result of a decrease in the average price
received for natural gas sold from $6.94 per Mcf for the year
ended December 31, 2008 to $2.81 per Mcf for the year ended
December 31, 2009, and a 45.9 MMcf decrease in natural
gas volumes sold.
Bad debt expense (recovery). Bad debt expense was
$2.2 million for the year ended December 31, 2008.
During the year ended December 31, 2009 there was no bad
debt expense or recovery.
As publicly reported on July 22, 2008, the crude oil
purchaser (Eaglwing L.P.) and its parent (SemGroup, L.P.) filed
voluntary petitions for reorganization under Chapter 11 of
the United States Bankruptcy Code. An allowance was set up for
the oil purchased from the Acquired Underlying Properties in the
amount of $2.2 million, which represents approximately 87%
of June 2008 sales made to Eaglwing, L.P.
Prices. The average price received for crude oil and
natural gas sold decreased primarily as a result of a decrease
in the oil price and natural gas price indices on which the
sales prices for a majority of the production were based.
68
Volumes. The small increase in oil and natural gas sales
volumes is primarily attributable to the development program
which was partially offset by the natural decline of the proved
producing properties.
Lease operating expenses. Lease operating expenses
remained stable at $6.0 million for the years ended
December 31, 2008 and 2009.
Production and property taxes. Production and property
taxes decreased $0.4 million as a result of the decrease in
revenues from oil and natural gas sales and decreased property
value on which these taxes are based.
Comparison
of Results of the Acquired Underlying Properties for the Years
Ended December 31, 2008 and 2007
Excess of revenues over direct operating expenses for the
Acquired Underlying Properties was $21.7 million for the
year ended December 31, 2008, compared to
$16.6 million for the year ended December 31, 2007.
The increase was primarily a result of an increase in the
average price received for the oil and natural gas sold. This
was partially offset by an increase in direct operating expenses.
Revenues. Revenues from oil and natural gas sales
increased $8.3 million between these periods. This increase
in revenues was primarily the result of an increase in the
average price received for crude oil sold from $66.96 per Bbl
for the year ended December 31, 2007 to $93.12 per Bbl for
the year ended December 31, 2008, and a 3.9 MBbl
decrease in oil volumes sold. The increase in revenues was also
the result of an increase in the average price received for
natural gas sold from $5.49 per Mcf for the year ended
December 31, 2007 to $6.94 per Mcf for the year ended
December 31, 2008, and a 23.1 MMcf decrease in natural
gas volumes sold.
Bad debt expense (recovery). Bad debt expense was
$2.2 million for the year ended December 31, 2008.
During the year ended December 31, 2007 there was no bad
debt expense or recovery.
As publicly reported on July 22, 2008, the crude oil
purchaser (Eaglwing L.P.) and its parent (SemGroup, L.P.) filed
voluntary petitions for reorganization under Chapter 11 of
the United States Bankruptcy Code. An allowance was set up for
the oil purchased from the Acquired Underlying Properties in the
amount of $2.2 million, which represents approximately 87%
of June 2008 sales made to Eaglwing, L.P.
Prices. The average price received for crude oil and
natural gas sold increased primarily as a result of an increase
in the oil price and natural gas price indices on which the
sales prices for a majority of the production were based.
Volumes. The decrease in oil and natural gas sales
volumes was primarily attributable to the natural decline of
proved producing volumes.
Lease operating expenses. Lease operating expenses
increased from $5.4 million for the year ended
December 31, 2007 to $6.0 million for the year ended
December 31, 2008. This increase was primarily a result of
an increase in primary vendor costs.
Production and property taxes. Production and property
taxes increased $0.4 million as a result of the increases
in the price of crude oil and in revenues from oil and natural
gas sales, on which these taxes are based.
69
HEDGE
CONTRACTS
The revenues derived from the Underlying Properties depend
substantially on prevailing crude oil prices and, to a lesser
extent, natural gas prices. As a result, commodity prices also
affect the amount of cash flow available for distribution to the
trust unitholders. Lower prices may also reduce the amount of
oil and natural gas that VOC Sponsor can economically produce.
VOC Sponsor sells the oil and natural gas production from the
Underlying Properties under floating market price contracts each
month. VOC Sponsor has entered into the hedge contracts for 2011
to reduce the exposure of the revenues from oil production from
the Underlying Properties to fluctuations in crude oil prices
and to achieve more predictable cash flow. However, these
contracts limit the amount of cash available for distribution if
prices increase above the fixed hedge price. The hedge contracts
consist of fixed price swap contracts that have been placed with
major trading counterparties in whom VOC Sponsor believes
represent minimal credit risks. VOC Brazos cannot provide
assurance, however, that these trading counterparties will not
become credit risks in the future.
The crude oil swap contracts will settle based on the average of
the settlement price for each commodity business day in the
contract month. In a swap transaction, the counterparty is
required to make a payment to VOC Sponsor for the difference
between the fixed price and the settlement price if the
settlement price is below the fixed price. VOC Sponsor is
required to make a payment to the counterparty for the
difference between the fixed price and the settlement price if
the settlement price is above the fixed price. From
January 1, 2011 through December 31, 2011, VOC
Sponsors crude oil price risk management positions in swap
contracts are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Price Swaps
|
|
|
|
|
Weighted
|
|
|
Volumes
|
|
Average Price
|
Month
|
|
(Bbls)
|
|
(Per Bbl)
|
|
January 2011
|
|
|
|
|
|
|
13,689
|
|
|
$
|
94.90
|
|
February 2011
|
|
|
|
|
|
|
13,621
|
|
|
$
|
94.90
|
|
March 2011
|
|
|
|
|
|
|
13,553
|
|
|
$
|
94.90
|
|
April 2011
|
|
|
|
|
|
|
13,486
|
|
|
$
|
94.90
|
|
May 2011
|
|
|
|
|
|
|
13,420
|
|
|
$
|
94.90
|
|
June 2011
|
|
|
|
|
|
|
13,354
|
|
|
$
|
94.90
|
|
July 2011
|
|
|
|
|
|
|
13,289
|
|
|
$
|
94.90
|
|
August 2011
|
|
|
|
|
|
|
13,224
|
|
|
$
|
94.90
|
|
September 2011
|
|
|
|
|
|
|
13,160
|
|
|
$
|
94.90
|
|
October 2011
|
|
|
|
|
|
|
13,096
|
|
|
$
|
94.90
|
|
November 2011
|
|
|
|
|
|
|
13,032
|
|
|
$
|
94.90
|
|
December 2011
|
|
|
|
|
|
|
12,970
|
|
|
$
|
94.90
|
|
The amounts received by VOC Sponsor from the hedge contract
counterparty upon settlement of the hedge contracts will reduce
the operating expenses related to the Underlying Properties in
calculating the net proceeds. However, if the hedge payments
received by VOC Sponsor under the hedge contracts exceed
operating expenses during a quarterly period, the ability to use
such excess amounts to offset operating expenses will be
deferred, with interest accruing on such amounts at the
prevailing prime rate, until the next quarterly period where the
hedge payments and the other non-production revenue are less
than such expenses. In addition, the aggregate amounts paid by
VOC Sponsor on settlement of the hedge contracts will reduce the
amount of net proceeds paid to the trust. See Computation
of net proceeds Net profits interest.
70
PRODUCING
ACREAGE AND WELL COUNTS
For the following data, gross refers to the total
number of wells or acres in which VOC Sponsor owns a working
interest and net refers to gross wells or acres
multiplied by the percentage working interest owned by VOC
Sponsor. Although many of VOC Sponsors wells produce both
oil and natural gas, a well is categorized as an oil well or a
natural gas well based upon the ratio of oil to natural gas
production. The Underlying Properties are interests in
properties located in oil and natural gas producing regions of
Kansas and Texas. The following is a summary of the approximate
acreage of the Underlying Properties at December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
|
(Acres)
|
|
|
Kansas
|
|
|
76,537
|
|
|
|
45,452.7
|
|
Texas
|
|
|
23,693
|
|
|
|
16,841.3
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
100,230
|
|
|
|
62,294.0
|
|
|
|
|
|
|
|
|
|
|
The following is a summary of the producing wells on the
Underlying Properties as of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operated Wells
|
|
|
Non-Operated Wells
|
|
|
Total
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Oil
|
|
|
814
|
|
|
|
516.1
|
|
|
|
34
|
|
|
|
8.4
|
|
|
|
848
|
|
|
|
524.5
|
|
Natural gas
|
|
|
30
|
|
|
|
20.4
|
|
|
|
14
|
|
|
|
5.3
|
|
|
|
44
|
|
|
|
25.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
844
|
|
|
|
536.5
|
|
|
|
48
|
|
|
|
13.7
|
|
|
|
892
|
|
|
|
550.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following is a summary of the number of developmental and
exploratory wells drilled by VOC Sponsor on the Underlying
Properties during the last three years. VOC Sponsor drilled two
exploratory wells during the periods presented.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Completed:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil wells
|
|
|
10
|
|
|
|
6.1
|
|
|
|
13
|
|
|
|
8.3
|
|
|
|
6
|
|
|
|
4.6
|
|
Natural gas wells
|
|
|
2
|
|
|
|
0.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-productive
|
|
|
5
|
|
|
|
2.2
|
|
|
|
4
|
|
|
|
2.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
17
|
|
|
|
9.1
|
|
|
|
17
|
|
|
|
10.7
|
|
|
|
6
|
|
|
|
4.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the nine months ended September 30, 2010, VOC
Sponsor drilled, completed and commenced production with respect
to eight wells on the Underlying Properties. During this period,
six wells were drilled in the Kansas Operating Area, four of
which were completed and are producing and two of which were
unsuccessful. VOC Sponsor, drilled and completed three Woodbine
C sand horizontal wells in the Texas Operating Area. VOC Sponsor
also recompleted two wells within pay zones in the Woodbine
interval.
71
The following table shows the average sales prices per Bbl of
oil and Mcf of natural gas produced and the production costs and
production and property taxes per Boe for the Underlying
Properties. Average prices do not include the effect of hedge
activity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Sales prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
67.15
|
|
|
$
|
93.67
|
|
|
$
|
55.16
|
|
Natural gas (per Mcf)
|
|
$
|
5.96
|
|
|
$
|
7.46
|
|
|
$
|
3.31
|
|
Lease operating expense (per Boe)
|
|
$
|
14.49
|
|
|
$
|
16.54
|
|
|
$
|
15.06
|
|
Production and property taxes (per Boe)
|
|
$
|
3.75
|
|
|
$
|
5.00
|
|
|
$
|
3.32
|
|
OPERATING
AREAS
The following table summarizes the estimated proved reserves by
operating area attributable to the Underlying Properties
according to the reserve reports, the corresponding pre-tax
PV-10 value
as of December 31, 2009 and the average net production
attributable to the Underlying Properties for the nine-month
period ended September 30, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
|
Proved Reserves (1)
|
|
|
Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of
|
|
|
September 30,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
2010 Average
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
% of
|
|
|
|
|
|
Pre-Tax
|
|
|
Net
|
|
|
|
Oil
|
|
|
Gas
|
|
|
Total
|
|
|
Total
|
|
|
PV-10
|
|
|
PV-10
|
|
|
Production
|
|
Operating Area
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBoe)
|
|
|
Reserves
|
|
|
Value (2)
|
|
|
Value
|
|
|
(Boe per day)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
Kansas (190 Fields)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fairport
|
|
|
799
|
|
|
|
|
|
|
|
799
|
|
|
|
6.1
|
%
|
|
$
|
10,624
|
|
|
|
5.9
|
%
|
|
|
124
|
|
Chase-Silica
|
|
|
405
|
|
|
|
|
|
|
|
405
|
|
|
|
3.1
|
%
|
|
|
5,508
|
|
|
|
3.1
|
%
|
|
|
86
|
|
Bindley
|
|
|
350
|
|
|
|
|
|
|
|
350
|
|
|
|
2.7
|
%
|
|
|
4,830
|
|
|
|
2.7
|
%
|
|
|
51
|
|
Marcotte
|
|
|
305
|
|
|
|
|
|
|
|
305
|
|
|
|
2.3
|
%
|
|
|
4,783
|
|
|
|
2.7
|
%
|
|
|
94
|
|
Moore-Johnson
|
|
|
353
|
|
|
|
|
|
|
|
353
|
|
|
|
2.7
|
%
|
|
|
4,777
|
|
|
|
2.7
|
%
|
|
|
52
|
|
Codell
|
|
|
137
|
|
|
|
|
|
|
|
137
|
|
|
|
1.1
|
%
|
|
|
3,268
|
|
|
|
1.8
|
%
|
|
|
30
|
|
Wesley
|
|
|
141
|
|
|
|
|
|
|
|
141
|
|
|
|
1.1
|
%
|
|
|
2,604
|
|
|
|
1.5
|
%
|
|
|
35
|
|
Mueller
|
|
|
149
|
|
|
|
|
|
|
|
149
|
|
|
|
1.1
|
%
|
|
|
2,421
|
|
|
|
1.4
|
%
|
|
|
30
|
|
Lippoldt
|
|
|
91
|
|
|
|
|
|
|
|
91
|
|
|
|
0.7
|
%
|
|
|
1,519
|
|
|
|
0.9
|
%
|
|
|
15
|
|
Dopita
|
|
|
99
|
|
|
|
|
|
|
|
99
|
|
|
|
0.8
|
%
|
|
|
1,369
|
|
|
|
0.8
|
%
|
|
|
20
|
|
Yaege
|
|
|
100
|
|
|
|
|
|
|
|
100
|
|
|
|
0.8
|
%
|
|
|
1,354
|
|
|
|
0.8
|
%
|
|
|
18
|
|
Monument North
|
|
|
64
|
|
|
|
|
|
|
|
64
|
|
|
|
0.5
|
%
|
|
|
1,330
|
|
|
|
0.7
|
%
|
|
|
27
|
|
Gerberding
|
|
|
20
|
|
|
|
771
|
|
|
|
148
|
|
|
|
1.1
|
%
|
|
|
1,277
|
|
|
|
0.7
|
%
|
|
|
35
|
|
Other
|
|
|
2,827
|
|
|
|
2,960
|
|
|
|
3,321
|
|
|
|
25.5
|
%
|
|
|
42,838
|
|
|
|
24.0
|
%
|
|
|
943
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kansas Total
|
|
|
5,840
|
|
|
|
3,731
|
|
|
|
6,462
|
|
|
|
49.7
|
%
|
|
$
|
88,500
|
|
|
|
49.5
|
%
|
|
|
1,559
|
|
Texas (3 Fields)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Kurten
|
|
|
3,851
|
|
|
|
2,732
|
|
|
|
4,306
|
|
|
|
33.1
|
%
|
|
$
|
56,513
|
|
|
|
31.6
|
%
|
|
|
705
|
|
Sand Flat
|
|
|
1,351
|
|
|
|
|
|
|
|
1,351
|
|
|
|
10.4
|
%
|
|
|
18,366
|
|
|
|
10.3
|
%
|
|
|
146
|
|
Hitts Lake North
|
|
|
888
|
|
|
|
|
|
|
|
888
|
|
|
|
6.8
|
%
|
|
|
15,311
|
|
|
|
8.6
|
%
|
|
|
172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas Total
|
|
|
6,090
|
|
|
|
2,732
|
|
|
|
6,545
|
|
|
|
50.3
|
%
|
|
$
|
90,190
|
|
|
|
50.5
|
%
|
|
|
1,024
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
11,930
|
|
|
|
6,463
|
|
|
|
13,007
|
|
|
|
100.0
|
%
|
|
$
|
178,690
|
|
|
|
100.0
|
%
|
|
|
2,583
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
In accordance with the rules and
regulations promulgated by the SEC, the proved reserves
presented above were determined using the twelve month
unweighted arithmetic average of the
first-day-of-the-month
price for the period from January 1, 2009 through
December 1, 2009, without giving effect to any hedge
transactions, and were held constant for the life of the
properties. This yielded a price for oil of $61.18 per barrel
and a price for natural gas of $3.83 per MMBtu.
|
72
|
|
|
(2) |
|
PV-10 is the
present value of estimated future net revenue to be generated
from the production of proved reserves, discounted using an
annual discount rate of 10%, calculated without deducting future
income taxes. Standardized measure of discounted net cash flows
is calculated the same as
PV-10 except
that it deducts future income taxes. Because the trust bears no
federal tax expense and taxable income is passed through to the
unitholders of the trust, no provision for federal or state
income taxes is included in the summary reserve reports and
therefore the standardized measure of discounted future net cash
flows attributable to the Underlying Properties is equal to the
pre-tax
PV-10 value.
PV-10 may not be considered a GAAP financial measure as defined
by the SEC and is derived from the standardized measure of
discounted future net cash flows, which is the most directly
comparable GAAP financial measure. The pre-tax
PV-10 value
and the standardized measure of discounted future net cash flows
do not purport to present the fair value of the oil and natural
gas reserves attributable to Underlying Properties. |
The Underlying Properties are located in Kansas and Texas in
areas characterized by long production histories and by several
additional development opportunities, which may help to diminish
natural declines in production from the Underlying Properties.
See Planned development and workover
program for a summary of VOC Sponsors development
plans. Based on the reserve reports, approximately 92% of the
future production from the Underlying Properties is expected to
be oil and approximately 8% is expected to be natural gas.
Kansas. As of December 31, 2009, proved
reserves attributable to the portion of the Kansas Underlying
Properties were approximately 6.5 MMBoe and are located in
three primary areas the Central Kansas Uplift,
Western Kansas and South Central Kansas. As of December 31,
2009, the Kansas Underlying Properties covered approximately
76,537 gross acres (45,452.7 net acres) and included
190 fields. As of December 31, 2009, the VOC Operators
operated 96% of the total proved reserves attributable to the
Kansas Underlying Properties based on
PV-10 value.
The major fields in the Central Kansas Uplift include Fairport
Field, Chase-Silica Field and Marcotte Field, all of which are
producing primarily from the Arbuckle and Lansing Kansas City
zones. The major fields in Western Kansas include the Bindley,
Moore-Johnson and Wesley fields, which are producing primarily
from the Mississippian, Morrow, Lansing Kansas City and Cherokee
zones. The major fields in South Central Kansas include the
Gerberding, Spivey Grabs and Alford fields, which are producing
primarily from the Mississippian, Simpson and Lansing Kansas
City zones. During the nine-month period ended
September 30, 2010, the average net production for the
Kansas Underlying Properties was approximately 1,559 Boe per day.
The following table summarizes VOC Sponsors interests in
the major fields in Kansas as of December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No. of Wells
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Operated/
|
|
|
|
|
|
|
|
|
|
Average
|
|
Net
|
|
|
Non-
|
|
|
|
|
|
Productive
|
|
Gross/
|
|
Working
|
|
Revenue
|
Field
|
|
Operated
|
|
Operator
|
|
County
|
|
Zones
|
|
Net Acres
|
|
Interest
|
|
Interest
|
|
Fairport
|
|
56/5
|
|
Vess Oil, Counts Ellis
|
|
Russell
|
|
Arbuckle, Dodge, LKC, Reagan, Wabaunsee
|
|
|
1,320/963.5
|
|
|
|
70.9
|
%
|
|
|
61.1
|
%
|
Chase-Silica
|
|
48/0
|
|
Vess Oil, Davis Petroleum, L D Drilling
|
|
Barton, Rice, Stafford
|
|
Arbuckle, LKC
|
|
|
2,760/2,038.1
|
|
|
|
84.0
|
%
|
|
|
69.4
|
%
|
Bindley
|
|
16/0
|
|
Vess Oil
|
|
Hodgeman
|
|
Mississippian
|
|
|
1,360/1,166.0
|
|
|
|
89.0
|
%
|
|
|
77.0
|
%
|
Marcotte
|
|
22/0
|
|
Vess Oil
|
|
Rooks
|
|
Arbuckle, LKC
|
|
|
1,760/1,676.7
|
|
|
|
95.9
|
%
|
|
|
79.7
|
%
|
Moore-Johnson
|
|
10/0
|
|
Vess Oil
|
|
Greeley
|
|
Morrow
|
|
|
1,621/1,292.3
|
|
|
|
79.7
|
%
|
|
|
64.6
|
%
|
73
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No. of Wells
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Operated/
|
|
|
|
|
|
|
|
|
|
Average
|
|
Net
|
|
|
Non-
|
|
|
|
|
|
Productive
|
|
Gross/
|
|
Working
|
|
Revenue
|
Field
|
|
Operated
|
|
Operator
|
|
County
|
|
Zones
|
|
Net Acres
|
|
Interest
|
|
Interest
|
|
Codell
|
|
2/0
|
|
Vess Oil
|
|
Rooks
|
|
Arbuckle, LKC
|
|
|
106/100.6
|
|
|
|
95.0
|
%
|
|
|
76.5
|
%
|
Wesley
|
|
5/0
|
|
L D Drilling, Davis Petroleum
|
|
Ness
|
|
Mississippian
|
|
|
480/446.7
|
|
|
|
92.2
|
%
|
|
|
79.9
|
%
|
Mueller
|
|
13/0
|
|
Vess Oil,
L D Drilling
|
|
Stafford
|
|
Arbuckle, Conglomerate, LKC
|
|
|
640/497.0
|
|
|
|
86.6
|
%
|
|
|
70.6
|
%
|
Lippoldt
|
|
6/0
|
|
Vess Oil
|
|
Hodgeman
|
|
Mississippian
|
|
|
1,280/604.8
|
|
|
|
47.3
|
%
|
|
|
41.3
|
%
|
Dopita
|
|
9/0
|
|
Vess Oil
|
|
Rooks
|
|
Arbuckle, Toronto
|
|
|
380/357.1
|
|
|
|
93.2
|
%
|
|
|
81.5
|
%
|
Yaege
|
|
26/0
|
|
Vess Oil
|
|
Riley
|
|
Hunton
|
|
|
2,098/1,094.1
|
|
|
|
52.2
|
%
|
|
|
45.6
|
%
|
Monument North
|
|
11/10
|
|
Vess Oil, McCoy Petroleum
|
|
Logan
|
|
Cherokee, Johnson
|
|
|
1,760/601.3
|
|
|
|
24.5
|
%
|
|
|
19.9
|
%
|
Gerberding
|
|
5/0
|
|
Vess Oil
|
|
Sumner
|
|
Mississippian, Simpson
|
|
|
800/570.0
|
|
|
|
71.9
|
%
|
|
|
58.3
|
%
|
Texas. As of December 31, 2009, proved reserves
attributable to the Texas Underlying Properties were
approximately 6.5 MMBoe and are located in two
areas Central Texas and East Texas. As of
December 31, 2009, the Texas Underlying Properties covered
approximately 23,693 gross acres (16,841.3 acres) and
included three fields. As of December 31, 2009, the VOC
Operators operated approximately 99% of the total proved
reserves attributable to the Texas Underlying Properties based
on PV-10
value.
Central Texas production is attributable to the Kurten Woodbine
Unit, which is producing primarily from the Woodbine Interval
and Buda Georgetown zones. East Texas properties include the
Sand Flat field and Hitts Lake North field, each of which is
producing primarily from the Paluxy and Chisum zones. During the
nine-month period ended September 30, 2010, the average net
production for the Texas Underlying Properties was approximately
1,024 Boe per day.
The following table summarizes VOC Sponsors interests in
the major fields in Texas as of December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
No. of Wells
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Operated/
|
|
|
|
|
|
|
|
|
|
Average
|
|
Net
|
|
|
Non-
|
|
|
|
|
|
Productive
|
|
Gross/
|
|
Working
|
|
Revenue
|
Field
|
|
Operated
|
|
Operator
|
|
County
|
|
Zones
|
|
Net Acres
|
|
Interest
|
|
Interest
|
|
Kurten
|
|
108/7
|
|
Vess Oil Corp, CML and Ogden Resources
|
|
Brazos
|
|
Austin Chalk, Woodbine Sand, Buda, Georgetown
|
|
|
20,908/15,280.4
|
|
|
|
72.5
|
%
|
|
|
58.0
|
%
|
Sand Flat
|
|
20/1
|
|
Vess Oil Corp., Carrizo
|
|
Smith
|
|
Paluxy, Rodessa
|
|
|
2,579/1,418.0
|
|
|
|
55.0
|
%
|
|
|
48.2
|
%
|
Hitts Lake North
|
|
6/0
|
|
Vess Oil Corp
|
|
Smith
|
|
Paluxy
|
|
|
206/142.9
|
|
|
|
59.9
|
%
|
|
|
52.9
|
%
|
PLANNED
DEVELOPMENT AND WORKOVER PROGRAM
The primary goals of VOC Sponsors development and workover
program have been to develop proved undeveloped reserves, manage
workovers and minimize the natural decline in
74
production in areas in which it operates. However, VOC Sponsor
is not obligated to undertake any development activities, so any
drilling and completing activities will be subject to the
reasonable discretion of VOC Sponsor. With respect to the
Underlying Properties, VOC Sponsor expects, but is not
obligated, to implement the following development strategies
specific to each of its primary operating areas.
|
|
|
|
|
Kansas. VOC Sponsors historical development
and workover program for the Kansas Underlying Properties has
included recompleting certain existing wells, drilling infill
development wells, conducting
3-D seismic
surveys, completing workovers and applying new production
technologies. VOC Sponsor intends to continue this program with
respect to the Kansas Underlying Properties, and expects to
incur total development expenditures for these properties during
the next five years of approximately $0.5 million, most of
which is expected to be incurred during 2010 by the planned
drilling of two vertical development wells.
|
|
|
|
Texas. VOC Sponsors historical development
program for the Texas Underlying Properties has included
recompleting certain existing wells, drilling infill development
wells, completing workovers and applying new production
technologies. In 2009, after an extensive review of horizontal
development drilling in the area, VOC Sponsor commenced drilling
horizontal wells in the Kurten Woodbine Unit in order to
accelerate the development of proved undeveloped reserves. VOC
Sponsor has successfully completed each of its first four
horizontal wells to the Woodbine C sand in this area with
average lateral lengths of approximately 3,000 feet. VOC
Sponsor intends to continue developing the Woodbine C sand
underlying the Kurten Woodbine Unit, utilizing horizontal wells
completed with multiple fracture stimulations together with
recompletions of existing vertical wellbores into additional pay
intervals. VOC Sponsor expects total development expenditures
for the Texas Underlying Properties during the next five years
to be approximately $24.8 million. Of this total, VOC
Sponsor contemplates spending approximately $21.5 million
to drill and complete 11 horizontal wells in the Woodbine C sand
and one vertical well in the Sand Flat Unit. The remaining
approximate $3.3 million is expected to be used for
recompletions and workovers of 13 Woodbine vertical wells to
additional Woodbine sands and six existing wells in the Sand
Flat Unit.
|
The trust is not directly obligated to pay any portion of any
development expenditures made with respect to the Underlying
Properties; however, development expenditures made by VOC
Sponsor with respect to the Underlying Properties will be
included among the costs that will be deducted from the gross
proceeds in calculating cash distributions attributable to the
Net Profits Interest. As a result, the trust will indirectly
bear an 80% share of any development expenditures made with
respect to the Underlying Properties (subject to certain
limitations near the end of the term of the trust, as described
below). Accordingly, higher or lower development expenditures
will, in general, directly decrease or increase, respectively,
the cash received by the trust. In making development
expenditure determinations, VOC Sponsor will attempt to balance
the impact of the development expenditures on current cash
distributions to the trust unitholders with the longer term
benefits of increased oil and natural gas production expected to
result from the development expenditure. In addition, VOC
Sponsor may establish a capital reserve of up to a maximum of
$1.0 million in the aggregate at any given time.
VOC Sponsor, as the designated operator of the Underlying
Properties, is entitled to make all determinations related to
development expenditures with respect to the Underlying
Properties, and there are no limitations on the amount of
development expenditures that VOC Sponsor may incur with respect
to the Underlying Properties, except as described below. VOC
Sponsor is required under the applicable Net Profits Interest
conveyance to use commercially reasonable efforts to
75
cause the operators of the Underlying Properties to operate
these properties as would a reasonably prudent operator acting
with respect to its own properties (without regard to the
existence of the Net Profits Interest). As the trust unitholders
would not be expected to fully realize the benefits of
development expenditures made with respect to the Underlying
Properties which occur near the end of the term of the trust,
during each twelve-month period beginning on the later to occur
of (1) December 31, 2027 and (2) the time when
9.0 MMBoe have been produced from the Underlying Properties
and sold (which is the equivalent of 7.2 MMBoe in respect
of the Net Profits Interest), development expenditures that may
be included among the costs that will be taken into account in
calculating net proceeds attributable to the Net Profits
Interest will be limited to the average annual development
expenditures incurred by VOC Sponsor during the preceding three
years, as adjusted for inflation. See Computation of net
proceeds Net Profits Interest.
RESERVE
REPORTS
Technologies. The reserve reports were prepared
using decline curve analyses to determine the reserves of the
Underlying Properties in Kansas and Texas. After estimating the
reserves of each proved developed property, it was determined
that a reasonable level of certainty exists with respect to the
reserves which can be expected from any individual undeveloped
well in the field. The consistency of reserves attributable to
the proved developed producing wells in Kansas and Texas, which
cover a wide area, further supports proved undeveloped
classification.
The proved undeveloped locations in Underlying Properties are
direct offsets of other producing wells.
3-D seismic
data has been used to target well placement for most proved
undeveloped locations in Kansas so as to avoid encountering
significant unfavorable faults or structural features. Data from
both VOC Sponsor and offset operators with which VOC Sponsor has
exchanged technical data demonstrate a consistency in this
resource play over an area much larger than the Underlying
Properties. In addition, information from other producing wells
has also been used to analyze reservoir properties such as
porosity, thickness, and stratigraphic conformity.
Internal controls. Cawley, Gillespie, &
Associates, Inc., the independent petroleum engineering
consultant, estimated all of the proved reserve information for
the Underlying Properties in this registration statement in
accordance with appropriate engineering, geologic, and
evaluation principles and techniques that are in accordance with
practices generally accepted in the petroleum industry, and
definitions and guidelines established by the SEC. These
reserves estimation methods and techniques are widely taught in
university petroleum curricula and throughout the
industrys ongoing training programs. Although these
engineering, geologic, and evaluation principles and techniques
are based upon established scientific concepts, the application
of such principles and techniques involves extensive judgment
and is subject to changes in existing knowledge and technology,
economic conditions and applicable statutory and regulatory
provisions. These same industry-wide applied techniques are used
in determining estimated reserve quantities. The technical
persons responsible for preparing the reserves estimates
presented herein meet the requirements regarding qualifications,
independence, objectivity and confidentiality set forth in the
Society of Petroleum Engineers Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserves Information.
Vice President of Operations of Vess Oil, William R. Horigan,
consults regularly with Cawley, Gillespie during the reserve
estimation process to review properties, assumptions, and any
new data available. Additionally, VOC Sponsors senior
management reviewed and approved all Cawley, Gillespie summary
reserve reports contained herein.
The independent engineering reserve estimates are reviewed by
Mr. Horigan, who has a Bachelor of Science in Chemical
Engineering, is a member of the Society of Petroleum Engineers
and served on the Executive Board for the Wichita Section. He is
also a member of the Producers Advisory Board of the KU Tertiary
Oil Recovery Project and a member of the Petroleum Technology
76
Transfer Council of the North Mid-Continent Region. He has over
35 years of oil and gas industry experience in drilling and
completions, reservoir engineering, and acquisitions and
divestitures.
Cawley, Gillespie & Associates, Inc. estimated oil and
natural gas reserves attributable to VOC Brazos and KEP as of
December 31, 2009. Numerous uncertainties are inherent in
estimating reserve volumes and values, and the estimates are
subject to change as additional information becomes available.
The reserves actually recovered and the timing of production of
the reserves may vary significantly from the original estimates.
The discounted estimated future net revenues presented below
were prepared using the twelve month unweighted arithmetic
average of the
first-day-of-the-month
price for the period from January 1, 2009 through
December 1, 2009, without giving effect to any derivative
transactions, and were held constant for the life of the
properties. This yielded a price for oil of $61.18 per barrel
and a price for natural gas of $3.83 per MMBtu. Oil equivalents
in the table are the sum of the Bbls of oil and the Boe of the
stated Mcfs of natural gas, calculated on the basis that six
Mcfs of natural gas is the energy equivalent of one Bbl of oil.
The estimated future net revenues attributable to the Net
Profits Interest as of December 31, 2009 are net of the
trusts proportionate share of all estimated costs deducted
from revenue pursuant to the terms of the conveyance creating
the Net Profits Interest and include only the reserves
attributable to the Underlying Properties that are expected to
be produced during the term of the trust. Because oil and
natural gas prices are influenced by many factors, use of the
twelve month unweighted arithmetic average of the
first-day-of-the-month
price for the period from January 1, 2009 through
December 1, 2009, as required by the SEC, may not be the
most accurate basis for estimating future revenues of reserve
data. Future net cash flows are discounted at an annual rate of
10%. There is no provision for federal income taxes with respect
to the future net cash flows attributable to the Underlying
Properties or the Net Profits Interest because future net
revenues are not subject to taxation at the VOC Sponsor or trust
level.
Proved reserves of Underlying Properties. The
following table sets forth, as of December 31, 2009,
certain estimated proved reserves, estimated future net revenues
and the discounted present value thereof attributable to the
Underlying Properties and the Net Profits Interest, in each case
derived from the reserve reports. Summaries of the reserve
reports are included in Annex A to this prospectus.
|
|
|
|
|
|
|
|
|
|
|
Underlying
|
|
Net Profits
|
|
|
Properties (1)
|
|
Interest (2)
|
|
|
(In thousands, except MBbls, MMcf and MBoe amounts)
|
|
Proved Reserves:
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
11,930
|
|
|
|
7,132
|
|
Natural gas (MMcf)
|
|
|
6,463
|
|
|
|
4,003
|
|
Oil equivalents (MBoe)
|
|
|
13,007
|
|
|
|
7,799
|
|
Future net revenues
|
|
$
|
371,468
|
|
|
$
|
238,175
|
|
Discounted estimated future net revenues (3)
|
|
$
|
178,690
|
|
|
|
|
|
Standardized measure (3)
|
|
$
|
178,690
|
|
|
|
|
|
|
|
|
(1)
|
|
Reserve volumes and estimated
future net revenues for Underlying Properties reflect volumes
and revenues attributable to VOC Sponsors net interests in
the properties comprising the Underlying Properties.
|
|
(2)
|
|
Reflects 80% of proved reserves
attributable to the Underlying Properties expected to be
produced during the term of the trust based on the reserve
reports.
|
|
(3)
|
|
The present values of future net
revenues for the Underlying Properties and the Net Profits
Interest were determined using a discount rate of 10% per annum.
As of September 30, 2010,
|
77
|
|
|
|
|
VOC Sponsor was structured as a limited partnership.
Accordingly, no provision for federal or state income taxes has
been provided because taxable income was passed through to the
partners of VOC Sponsor. Therefore, the standardized measure of
the Underlying Properties is equal to the
PV-10 value,
which totaled $178.7 million as of December 31, 2009. |
Information concerning historical changes in net proved reserves
attributable to the Underlying Properties is contained in the
unaudited supplemental information contained elsewhere in this
prospectus. VOC Sponsor has not filed reserve estimates covering
the Underlying Properties with any other federal authority or
agency.
The following table summarizes the changes in estimated proved
reserves of the Underlying Properties for the periods indicated.
The data is presented assuming VOC Sponsor owns all the
Underlying Properties as of December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Equivalents
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBoe)
|
|
|
Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
|
13,031
|
|
|
|
7,927
|
|
|
|
14,352
|
|
Revisions, extensions, discoveries and additions
|
|
|
(333
|
)
|
|
|
191
|
|
|
|
(301
|
)
|
Production
|
|
|
(705
|
)
|
|
|
(738
|
)
|
|
|
(828
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
11,993
|
|
|
|
7,380
|
|
|
|
13,223
|
|
Revisions, extensions, discoveries and additions
|
|
|
(1,611
|
)
|
|
|
227
|
|
|
|
(1,573
|
)
|
Production
|
|
|
(704
|
)
|
|
|
(750
|
)
|
|
|
(829
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
9,678
|
|
|
|
6,857
|
|
|
|
10,821
|
|
Revisions, extensions, discoveries and additions
|
|
|
2,984
|
|
|
|
298
|
|
|
|
3,032
|
|
Production
|
|
|
(732
|
)
|
|
|
(693
|
)
|
|
|
(847
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
11,930
|
|
|
|
6,463
|
|
|
|
13,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
|
12,355
|
|
|
|
7,596
|
|
|
|
13,621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
11,416
|
|
|
|
7,122
|
|
|
|
12,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
8,952
|
|
|
|
6,562
|
|
|
|
10,046
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
10,567
|
|
|
|
5,813
|
|
|
|
11,536
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2006
|
|
|
677
|
|
|
|
330
|
|
|
|
732
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007
|
|
|
577
|
|
|
|
258
|
|
|
|
620
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008
|
|
|
726
|
|
|
|
295
|
|
|
|
775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009
|
|
|
1,363
|
|
|
|
649
|
|
|
|
1,471
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SALE AND
ABANDONMENT OF UNDERLYING PROPERTIES
VOC Sponsor and any transferee of an Underlying Property will
have the right to abandon its interest in any well or property
if it reasonably believes a well or property ceases to produce
or is not capable of producing in commercially paying
quantities. To reduce the potential conflict of interest between
VOC Sponsor and the trust in determining whether a well is
capable of producing in commercially paying quantities, VOC
Sponsor is required under the applicable conveyance to cause the
operators of the Underlying Properties to operate these
properties as would a reasonably prudent operator acting with
respect to its own properties (without regard to the existence
of the Net Profits Interest). Upon termination of the lease, the
portion of the net
78
profits interest relating to the abandoned property will be
extinguished. For the years ended December 31, 2007, 2008
and 2009, VOC Sponsor plugged and abandoned zero, six and
15 wells, respectively, located on leases within the
Underlying Properties based on its determination that such wells
could no longer produce oil or natural gas in commercially
economic quantities. The number of wells abandoned during this
time period accounted for less than 3% of the producing wells
attributable to the Underlying Properties.
VOC Sponsor generally may sell all or a portion of its interests
in the Underlying Properties, subject to and burdened by the Net
Profits Interest, without the consent of the trust unitholders.
In addition, VOC Sponsor may, without the consent of the trust
unitholders, require the trust to release the Net Profits
Interest associated with any lease that accounts for less than
or equal to 0.25% of the total production from the Underlying
Properties in the prior 12 months and provided that the Net
Profits Interest covered by such releases cannot exceed, during
any 12-month
period, an aggregate fair market value to the trust of $500,000.
These releases will be made only in connection with a sale by
VOC Sponsor to a non-affiliate of the relevant Underlying
Properties and are conditioned upon the trust receiving an
amount equal to the fair value to the trust of such Net Profits
Interest. Any net sales proceeds paid to the trust are
distributable to trust unitholders for the quarter in which they
are received. VOC Sponsor has not identified for sale any of the
Underlying Properties.
MARKETING
AND POST-PRODUCTION SERVICES
Pursuant to the terms of the conveyance creating the Net Profits
Interest, VOC Sponsor will have the responsibility to market, or
cause to be marketed, the oil and natural gas production
attributable to the Underlying Properties. The terms of the
conveyance creating the Net Profits Interest do not permit VOC
Sponsor to charge any marketing fee when determining the net
proceeds upon which the Net Profits Interest will be calculated.
As a result, the net proceeds to the trust from the sales of oil
and natural gas production from the Underlying Properties will
be determined based on the same price that VOC Sponsor receives
for oil and natural gas production attributable to VOC
Sponsors remaining interest in the Underlying Properties.
Texas is a mature oil producing state with a well-developed
crude oil refining, transportation and marketing infrastructure.
According to the Texas Railroad Commission, more than 5,000
operators reported oil production of approximately
377 million barrels for the state of Texas during 2009.
There were 26 operating oil refineries located in Texas in 2009
with combined capacity to refine over 4.6 million barrels
of oil per day. With oil production in the state of Texas
averaging just over 1 million barrels of oil per day, Texas
refineries are net importers of crude oil. As a result, oil
producers in Texas benefit from competitive marketing conditions
for their oil production as a result of the high demand from the
crude oil marketing companies and refineries located in Texas.
Kansas is a mature oil producing state with a well-developed
transportation infrastructure for crude oil transportation and
marketing. According to the Kansas Geological Society, more than
2,100 operators reported oil production of approximately
39 million barrels for the state of Kansas during 2009.
Kansas is home to three oil refineries located in McPherson, El
Dorado and Coffeyville, Kansas. These refineries have combined
capacity to refine over 300,000 barrels of oil per day.
With oil production in the state of Kansas averaging less than
100,000 barrels of oil per day, Kansas is a net importer of
crude oil. As a result, Kansas operators benefit from the
competitive marketing conditions for their oil production as a
result of the high demand from the refineries located in Kansas.
During the nine months ended September 30, 2010, VOC
Sponsor sold approximately 32% of the oil produced from the
Underlying Properties to MV Purchasing, LLC, an affiliate of VOC
79
Sponsor. The remaining oil production is sold to third-party
crude oil purchasers. These purchasers buy crude oil from VOC
Sponsor under short-term contracts using market sensitive
pricing. VOC Sponsor does not believe that the loss of any of
these parties, including MV Purchasing LLC, as a purchaser of
crude oil production from the Underlying Properties would have a
material impact on the business or operations of VOC Sponsor or
the Underlying Properties because of the competitive marketing
conditions in Texas and Kansas as described above.
Oil production is typically transported by truck from the field
to the closest gathering facility or refinery. VOC Sponsor sells
the majority of the oil production from the Underlying
Properties under short-term contracts using market sensitive
pricing. The price received by VOC Sponsor for the oil
production from the Underlying Properties is usually based on
the NYMEX price applied to equal daily quantities on the month
of delivery that is then reduced for differentials based upon
delivery location and oil quality.
All natural gas produced by VOC Sponsor is marketed and sold to
third-party purchasers. The natural gas is sold on contract
basis and the contracts are in their secondary terms and are on
a
month-to-month
basis. In all cases, the contract price is based on a percentage
of a published regional index price, after adjustments for Btu
content, transportation and related charges.
TITLE TO
PROPERTIES
The properties comprising the Underlying Properties are subject
to certain burdens that are described in more detail below. To
the extent that these burdens and obligations affect VOC
Sponsors rights to production and the value of production
from the Underlying Properties, they have been taken into
account in calculating the trusts interests and in
estimating the size and the value of the reserves attributable
to the Underlying Properties.
VOC Sponsors interests in the oil and natural gas
properties comprising the Underlying Properties are typically
subject, in one degree or another, to one or more of the
following:
|
|
|
|
|
royalties, overriding royalties and other burdens, express and
implied, under oil and natural gas leases;
|
|
|
|
overriding royalties, production payments and similar interests
and other burdens created by VOC Sponsors predecessors in
title;
|
|
|
|
a variety of contractual obligations arising under operating
agreements, farm-out agreements, production sales contracts and
other agreements that may affect the Underlying Properties or
their title;
|
|
|
|
liens that arise in the normal course of operations, such as
those for unpaid taxes, statutory liens securing unpaid
suppliers and contractors and contractual liens under operating
agreements that are not yet delinquent or, if delinquent, are
being contested in good faith by appropriate proceedings;
|
|
|
|
pooling, unitization and communitization agreements,
declarations and orders;
|
|
|
|
easements, restrictions,
rights-of-way
and other matters that commonly affect property;
|
|
|
|
conventional rights of reassignment that obligate VOC Sponsor to
reassign all or part of a property to a third party if VOC
Sponsor intends to release or abandon such property; and
|
80
|
|
|
|
|
rights reserved to or vested in the appropriate governmental
agency or authority to control or regulate the Underlying
Properties and the Net Profits Interest therein.
|
VOC Sponsor believes that the burdens and obligations affecting
the properties comprising the Underlying Properties are
conventional in the industry for similar properties. VOC Sponsor
also believes that the existing burdens and obligations do not,
in the aggregate, materially interfere with the use of the
Underlying Properties and will not materially adversely affect
the value of the Net Profits Interest.
VOC Sponsor acquired the Underlying Properties over the past
30 years. At the time of its acquisition of the Underlying
Properties, VOC Sponsor retained outside counsel to examine
title to the Underlying Properties as to the acquired interests.
VOC Sponsor subsequently retained outside counsel to update
title to the Underlying Properties in September 2010.
VOC Sponsor will record the conveyance of the Net Profits
Interest in Kansas and Texas in the real property records in
each Kansas or Texas county in which the Underlying Properties
are located. Although under Texas law it is well-established
that the recording in the appropriate real property records of
an interest such as the Net Profits Interest will constitute the
conveyance of a fully vested real property interest to the
trust, the law in Kansas is less certain. VOC Sponsor and the
trust believe, based upon an opinion of counsel, that the
recording in the appropriate real property records in Kansas of
the Net Profits Interest should constitute the conveyance of a
fully vested real property interest, interests in hydrocarbons
in place or to be produced or a production payment as such is
defined under the United States Bankruptcy Code; however, there
is no dispositive Kansas Supreme Court case directly addressing
these issues. In a bankruptcy of VOC Sponsor, creditors of VOC
Sponsor would be able to claim the Net Profits Interest as an
asset of the bankruptcy estate to satisfy obligations to them if
the conveyance of the Net Profits Interest did not constitute
the conveyance of a real property interest or interests in
hydrocarbons in place or to be produced under applicable state
law or a production payment, in which case the trust would be an
unsecured creditor of VOC Sponsor at risk of losing the entire
value of the Net Profit Interests to senior creditors.
VOC Sponsor believes that its title to the Underlying Properties
is, and the trusts title to the Net Profits Interest will
be, good and defensible in accordance with standards generally
accepted in the oil and gas industry, subject to such exceptions
as are not so material to detract substantially from the use or
value of such properties or royalty interests. Please see
Risk factorsThe trust units may lose value as a
result of title deficiencies with respect to the Underlying
Properties.
COMPETITION
AND MARKETS
The oil and natural gas industry is highly competitive. VOC
Sponsor competes with major oil and natural gas companies and
independent oil and natural gas companies for oil and natural
gas, equipment, personnel and markets for the sale of oil and
natural gas. Many of these competitors are financially stronger
than VOC Sponsor, but even financially troubled competitors can
affect the market because of their need to sell oil and natural
gas at any price to attempt to maintain cashflow. The trust will
be subject to the same competitive conditions as VOC Sponsor and
other companies in the oil and natural gas industry.
Oil and natural gas compete with other forms of energy available
to customers, primarily based on price. These alternate forms of
energy include electricity, coal and fuel oils. Changes in the
availability or price of oil, natural gas or other forms of
energy, as well as business conditions, conservation,
legislation, regulations and the ability to convert to alternate
fuels and other forms of energy may affect the demand for oil
and natural gas.
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Future price fluctuations for oil and natural gas will directly
impact trust distributions, estimates of reserves attributable
to the trusts interests and estimated and actual future
net revenues to the trust. In view of the many uncertainties
that affect the supply and demand for oil and natural gas,
neither the trust nor VOC Sponsor can make reliable predictions
of future oil and natural gas supply and demand, future product
prices or the effect of future product prices on the trust.
ENVIRONMENTAL
MATTERS AND REGULATION
General. The oil and natural gas exploration and
production operations of VOC Sponsor are subject to stringent
and comprehensive federal, regional, state and local laws and
regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection.
These laws and regulations may impose significant obligations on
VOC Sponsors operations, including requirements to:
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obtain permits to conduct regulated activities;
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limit or prohibit drilling activities on certain lands lying
within wilderness, wetlands and other protected areas;
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restrict the types, quantities and concentration of materials
that can be released into the environment in the performance of
drilling and production activities;
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initiate remedial activities or corrective actions to mitigate
pollution from former or current operations, such as restoration
of drilling pits and plugging of abandoned wells;
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apply specific health and safety criteria addressing worker
protection; and
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impose substantial liabilities on VOC Sponsor for pollution
resulting from VOC Sponsors operations.
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Failure to comply with environmental laws and regulations may
result in the assessment of administrative, civil and criminal
sanctions, including monetary penalties, the imposition of
investigatory and remedial obligations, and the issuance of
injunctions limiting or prohibiting some or all of our
operations. Moreover, these laws, rules and regulations may
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.
VOC Sponsor believes that it is in substantial compliance with
all existing environmental laws and regulations applicable to
its current operations and that its continued compliance with
existing requirements will not have a material adverse effect on
the cash distributions to the trust unitholders. However, 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 emission or discharge limits
or waste handling, disposal or remediation obligations could
have a material adverse effect on VOC Sponsors development
expenditures, results of operations and financial position. VOC
Sponsor may be unable to pass on those increases to its
customers.
The following is a summary of the more significant existing
environmental, health and safety laws and regulations, each as
amended from time to time, to which VOC Sponsors business
operations are subject.
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Hazardous substance and wastes. The Comprehensive
Environmental Response, Compensation and Liability Act, or
CERCLA, also known as the Superfund law, and
comparable state laws impose liability without regard to fault
or the legality of the original conduct on certain classes of
persons who are considered to be responsible for the release of
a hazardous substance into the environment. Under
CERCLA, these responsible persons may include the
owner or operator of the site where the release occurred, and
entities that transport or disposed or arranged for the
transport or disposal of hazardous substances released at the
site. These responsible persons may be subject to joint and
several, strict liability for the costs of cleaning up the
hazardous substances that have been released into the
environment, for damages to natural resources and for the costs
of certain health studies. CERCLA also authorizes the
U.S. Environmental Protection Agency, or EPA
and, in some instances, third parties to act n response to
threats to the public health or the environment and to seek to
recover from the responsible classes of persons the costs they
incur. It is not uncommon for neighboring landowners and other
third-parties to file claims for personal injury and property
damage allegedly caused by the hazardous substances released
into the environment. VOC Sponsor generates materials in the
course of its operations that may be regulated as hazardous
substances.
The Resource Conservation and Recovery Act, or RCRA,
and comparable state laws regulate the generation,
transportation, treatment, storage, disposal and cleanup of
hazardous and non-hazardous wastes. Under the auspices of the
EPA, the individual states administer some or all of the
provisions of RCRA, sometimes in conjunction with their own,
more stringent requirements. Drilling fluids, produced waters
and most of the other wastes associated with the exploration,
production and development of crude oil or natural gas are
currently regulated under RCRAs non-hazardous waste
provisions. However, it is possible that certain oil and natural
gas exploration and production wastes now classified as
non-hazardous could be classified as hazardous wastes in the
future. Any such change could result in an increase in the costs
to manage and dispose of wastes, which could have a material
adverse effect on the cash distributions to the trust
unitholders. In addition, VOC Sponsor generates industrial
wastes in the ordinary course of its operations that may be
regulated as hazardous wastes.
The real properties upon which VOC Sponsor conducts its
operations have been used for oil and natural gas exploration
and production for many years. Although VOC Sponsor may have
utilized operating and disposal practices that were standard in
the industry at the time, petroleum hydrocarbons and wastes may
have been disposed of or released on or under the real
properties upon which VOC Sponsor conducts its operations, or on
or under other, offsite locations, where these petroleum
hydrocarbons and wastes have been taken for recycling or
disposal. In addition, the real properties upon which VOC
Sponsor conducts its operations may 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 VOC Sponsors control. These real properties and the
petroleum hydrocarbons and wastes disposed or released thereon
may be subject to CERCLA, RCRA and analogous state laws. Under
such laws, VOC Sponsor could be required to remove or remediate
previously disposed wastes, to clean up contaminated property,
and to perform remedial operations such as restoration of pits
and plugging of abandoned wells to prevent future contamination.
Water discharges and hydraulic fracturing. The
Federal Water Pollution Control Act, also known as the
Clean Water Act, and analogous state laws impose
restrictions and strict controls with respect to the discharge
of pollutants, including spills and leaks of oil, into federal
and 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. Any
unpermitted discharge of pollutants could result in penalties
and significant remedial obligations. Spill prevention, control
and countermeasure requirements under federal law require
appropriate containment berms and
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similar structures to help prevent the contamination of
navigable waters in the event of a petroleum hydrocarbon tank
spill, rupture or leak.
It is customary to recover oil and natural gas from deep shale
and tight sand 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 gas production. Due to public concerns raised
regarding 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 EPA has commenced a study of the potential environmental
impacts of hydraulic fracturing activities, with results of the
study anticipated to be available by late 2012, and a committee
of the U.S. House of Representatives is also conducting an
investigation of hydraulic fracturing practices. Legislation has
been introduced before Congress to provide for federal
regulation of hydraulic fracturing and to require disclosure of
the chemicals used in the fracturing process. In addition, some
states have adopted, and other states are considering adopting,
regulations that could restrict hydraulic fracturing in certain
circumstances. For example, New York has imposed a de facto
moratorium on the issuance of permits for high-volume,
horizontal hydraulic fracturing until state-administered
environmental studies are completed, a draft of which must be
published by June 1, 2011, followed by a
30-day
comment period. Further, Pennsylvania has adopted a variety of
regulations limiting how and where fracturing can be performed.
If new laws or regulations that significantly restrict hydraulic
fracturing are adopted, such legal requirements could make it
more difficult or costly for VOC Sponsor to perform hydraulic
fracturing activities. Moreover, VOC Sponsor believes that
enactment of legislation regulating hydraulic fracturing at the
federal level may have a material adverse effect on its business.
Air emissions. The federal Clean Air Act and
comparable state laws restrict the emission of air pollutants
from many sources through air emissions permitting programs and
also impose various monitoring and reporting requirements. These
laws and regulations may require VOC Sponsor to obtain
pre-approval for the construction or modification of certain
projects or facilities expected to produce or significant
increase air emissions, obtain and strictly comply with
stringent air permit requirements or incur development
expenditures to install and utilize specific equipment or
technologies to control emissions. Obtaining permits has the
potential to delay the development of oil and natural gas
projects. Federal and state regulatory agencies may 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.
Climate change. In response to certain scientific
studies suggesting that emissions of certain gases, commonly
referred to as greenhouse gases, or GHGs, and
including carbon dioxide and methane, are contributing to the
warming of the Earths atmosphere and other climatic
conditions, both houses of Congress have actively considered
legislation to reduce emissions of GHGs, and 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. These allowances would be expected to escalate
significantly in cost over time. Although it is not possible at
this time to predict when Congress may pass climate change
legislation, any future federal or state laws that may be
adopted to address GHG emissions could require VOC Sponsor to
incur increased operating costs and could adversely affect
demand for the oil and natural gas VOC Sponsor produces.
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In addition, on December 15, 2009, the EPA published its
findings that emissions of GHGs present an endangerment to
public heath and the environment. These findings allow 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. Most recently,
on August 12, 2010, EPA proposed two actions to govern the
implementation of PSD permitting requirements for GHGs in states
whose existing State Implementation Plans (SIPs) do
not accommodate the regulation of GHGs. First, EPA has proposed
to issue a Finding of Substantial Inadequacy and SIP
Call to 13 such States. Second, EPA has proposed to establish a
Federal Implementation Plan in any state that does not revise
its SIP to accommodate GHG permitting. In addition, on
November 30, 2010, the EPA published its final its
regulations expanding the existing GHG monitoring and reporting
rule to include onshore and offshore oil and natural gas
production facilities and onshore oil and natural gas
processing, transmission, storage, and distribution facilities.
Reporting of GHG emissions from such facilities will be required
on an annual basis, with reporting beginning in 2012 for
emissions occurring in 2011. The adoption of any regulations
that requires reporting of GHGs or otherwise limits emissions of
GHGs from the equipment and operations of VOC Sponsor could
require VOC Sponsor to incur costs to monitor and report on GHG
emissions or reduce emissions of GHGs associated with its
operations, and such requirements also could adversely affect
demand for the oil and natural gas that VOC Sponsor produces.
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, floods and other climatic events. If any
such effects were to occur, they could adversely affect or delay
demand for the oil or natural gas produced by VOC Sponsor or
otherwise cause VOC Sponsor to incur significant costs in
preparing for or responding to those effects.
Endangered Species Act. The federal Endangered
Species Act, or ESA, restricts activities that may
affect endangered and threatened species or their habitats. The
designation of previously unidentified endangered or threatened
species could cause VOC Sponsor to incur additional costs or
become subject to operating delays, restrictions or bans in the
affected areas. While some of VOC Sponsors facilities or
leased acreage may be located in areas that are designated as
habitat for endangered or threatened species, VOC Sponsor
believes that it is in substantial compliance with the ESA.
Employee health and safety. The operations of VOC
Sponsor are subject to a number of federal and state laws and
regulations, including the federal Occupational Safety and
Health Act, 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 EPA
community
right-to-know
regulations under Title III of the federal Superfund
Amendment and Reauthorization Act and comparable state statutes
require that information be maintained concerning hazardous
materials used or produced in operations and that this
information be provided to employees, state and local government
authorities and citizens. VOC Sponsor believes that it is in
substantial compliance with all applicable laws and regulations
relating to worker health and safety.
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COMPUTATION
OF NET PROCEEDS
The provisions of the conveyance governing the computation of
the net proceeds are detailed and extensive. The following
information summarizes the material information contained in the
conveyance related to the computation of the net proceeds. This
summary may not contain all information that is important to
you. For more detailed provisions concerning the Net Profits
Interest, you should read the conveyance. A copy of the
conveyance has been filed as an exhibit to the registration
statement. See Where you can find more information.
NET
PROFITS INTEREST
Under the conveyance, 80% of the aggregate net proceeds
attributable to the sale of oil and natural gas production from
the Underlying Properties for each calendar quarter will be paid
to the trust on or before the 25th day of the month
following the end of each quarter. VOC Sponsor will not pay to
the trust any interest on the net proceeds held by VOC Sponsor
prior to payment to the trust. The trustee will make
distributions to trust unitholders quarterly. See
Description of the trust units Distributions
and income computations.
Gross proceeds means the aggregate amount
received by VOC Sponsor from sales of oil and natural gas
produced from the Underlying Properties (other than amounts
received for certain future non-consent operations). However,
gross proceeds does not include consideration for the transfer
or sale of any underlying property by VOC Sponsor or any
subsequent owner to any new owner unless the net profits
interest is released (as is permitted in certain circumstances).
Gross proceeds also does not include any amount for oil or
natural gas lost in production or marketing or used by the owner
of the Underlying Properties in drilling, production and plant
operations. Gross proceeds includes payments for future
production if they are not subject to repayment in the event of
insufficient subsequent production.
Net proceeds means gross proceeds less the
following costs:
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all payments to mineral or landowners, such as royalties,
overriding royalties or other burdens against production, delay
rentals, shut-in oil and natural gas payments, minimum royalty
or other payments for drilling or deferring drilling;
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any taxes paid by the owner of an Underlying Property to the
extent not deducted in calculating gross proceeds, including
estimated and accrued general property (ad valorem), production,
severance, sales, gathering, excise and other taxes;
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the aggregate amount paid by VOC Sponsor upon settlement of
hedge contracts on a quarterly basis, as specified in the hedge
contracts;
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any extraordinary taxes or windfall profits taxes that may be
assessed in the future that are based on profits realized or
prices received for production from the Underlying Properties;
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costs paid by an owner of a property comprising the Underlying
Properties under any joint operating agreement pursuant to the
terms of the conveyance;
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all other costs and expenses, development costs and liabilities
of exploring for, drilling, recompleting, workovers, operating
and producing oil and natural gas, including allocated expenses
such as labor, vehicle and travel costs and materials and any
plugging and abandonment liabilities (net of any development
costs for which a reserve had already
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been made to the extent such development costs are incurred
during the computation period) other than costs and expenses for
certain future non-consent operations;
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costs or charges associated with gathering, treating and
processing oil and natural gas, (provided, however, that any
proceeds attributable to treatment or processing will offset
such costs or changes, if any);
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any overhead charge incurred pursuant to any operating agreement
or other arrangement relating to an Underlying Property as
permitted under the applicable conveyance, including the
overhead fees payable by VOC Sponsor to VOC Operators and Vess
Texas LLC as described in Certain relationship and related
party transactions;
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costs for recording the conveyance and costs estimated to record
the termination and for release of the conveyance;
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costs paid to counterparties under the hedge contracts or to the
persons that provide credit to maintain any hedge contracts,
excluding any hedge settlement amounts;
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amounts previously included in gross proceeds but subsequently
paid as a refund, interest or penalty;
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costs and expenses for renewals or extensions of leases; and
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at the option of VOC Sponsor (or any subsequent owner of the
Underlying Properties), amounts reserved for approved
development expenditure projects, including well drilling,
recompletion and workover costs, which amounts will at no time
exceed $1.0 million in the aggregate, and will be subject
to the limitations described below (provided that such costs
shall not be debited from gross proceeds when actually incurred).
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All of the hedge payments received by VOC Sponsor from hedge
contract counterparties upon settlements of hedge contracts and
certain other non-production revenues, including salvage value
for equipment related to plugged and abandoned wells, as
detailed in the conveyance, will offset the costs outlined above
in calculating the net proceeds. If the hedge payments received
by VOC Sponsor and certain other non-production revenues exceed
the costs during a quarterly period, the ability to use such
excess amounts to offset costs will be deferred and utilized as
offsets in the next quarterly period to the extent such amounts,
plus accrued interest thereon, together with other offsets to
costs, for the applicable quarter, are less than the costs
arising in such quarter. If any excess amounts have not been
used to offset costs at the time when the later to occur of
(1) December 31, 2030, or (2) the time when
9.7 MMBoe (which is the equivalent of 7.8 MMBoe in
respect of the Net Profits Interest) have been produced from the
Underlying Properties and sold, then trust unitholders will not
be entitled to receive the benefit of such excess amounts.
During each twelve-month period beginning on the later to occur
of (1) December 31, 2027 and (2) the time when
9.0 MMBoe have been produced from the Underlying Properties
and sold (which is the equivalent of 7.2 MMBoe in respect
of the Net Profits Interest) (in either case, the Capital
Expenditure Limitation Date), the sum of the development
expenditures and amounts reserved for approved development
expenditure projects for such twelve-month period may not exceed
the Average Annual Capital Expenditure Amount. The Average
Annual Capital Expenditure Amount means the quotient of
(x) the sum of the development expenditures and amounts
reserved for approved development expenditure projects with
respect to the three twelve-month periods ending on the Capital
Expenditure Limitation Date, divided by (y) three.
Commencing on the Capital Expenditure Limitation Date, and each
anniversary of the Capital
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Expenditure Limitation Date thereafter, the Average Annual
Capital Expenditure Amount will be increased by 2.5% to account
for expected increased costs due to inflation.
In the event that the net proceeds for any computation period is
a negative amount, the trust will receive no payment for that
period, and any such negative amount plus accrued interest will
be deducted from gross proceeds in the following computation
period for purposes of determining the net proceeds for that
following computation period.
Gross proceeds and net proceeds are calculated on a cash basis,
except that certain costs, primarily ad valorem taxes and
expenditures of a material amount, may be determined on an
accrual basis.
ADDITIONAL
PROVISIONS
If a controversy arises as to the sales price of any production,
then for purposes of determining gross proceeds:
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amounts withheld or placed in escrow by a purchaser are not
considered to be received by the owner of the Underlying
Property until actually collected;
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amounts received by the owner of the Underlying Property and
promptly deposited with a nonaffiliated escrow agent will not be
considered to have been received until disbursed to it by the
escrow agent; and
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amounts received by the owner of the Underlying Property and not
deposited with an escrow agent will be considered to have been
received.
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The trustee is not obligated to return any cash received from
the Net Profits Interest. Any overpayments made to the trust by
VOC Sponsor due to adjustments to prior calculations of net
proceeds or otherwise will reduce future amounts payable to the
trust until VOC Sponsor recovers the overpayments plus interest
at the prime rate.
The conveyance generally permits VOC Sponsor to transfer without
the consent or approval of the trust unitholders all or any part
of its interest in the Underlying Properties, subject to the Net
Profits Interest. The trust unitholders are not entitled to any
proceeds of a sale or transfer of VOC Sponsors interest
unless the trust sells the Net Profits Interest as to such
interest. Following a sale or transfer, the Underlying
Properties will continue to be subject to the Net Profits
Interest, and the net proceeds attributable to the transferred
property will be calculated as part of the computation of net
proceeds described in this prospectus.
In addition, VOC Sponsor may, without the consent of the trust
unitholders, require the trust to release the Net Profits
Interest associated with any lease that accounts for less than
or equal to 0.25% of the total production from the Underlying
Properties in the prior 12 months and provided that the Net
Profits Interest covered by such releases cannot exceed, during
any 12-month
period, an aggregate fair market value to the trust of $500,000.
These releases will be made only in connection with a sale by
VOC Sponsor to a non-affiliate of the relevant Underlying
Properties and are conditioned upon the trust receiving an
amount equal to the fair value to the trust of such Net Profits
Interest. Any net sales proceeds paid to the trust are
distributable to trust unitholders for the quarter in which they
are received. VOC Sponsor has not identified for sale any of the
Underlying Properties.
As the designated operator of a property comprising the
Underlying Properties, VOC Sponsor may enter into farm-out,
operating, participation and other similar agreements to develop
the
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property. VOC Sponsor may enter into any of these agreements
without the consent or approval of the trustee or any trust
unitholder.
VOC Sponsor and any transferee of an Underlying Property will
have the right to abandon its interest in any well or property
if it reasonably believes the well or property ceases to produce
or is not capable of producing in commercially paying
quantities. In making such decisions, VOC Sponsor or any
transferee of an Underlying Property is required under the
applicable conveyance to operate, or to use commercially
reasonable efforts to cause the operators of the Underlying
Properties to operate these properties as would a reasonably
prudent operator acting with respect to its own properties
(without regard to the existence of the Net Profits Interest).
Upon termination of the lease, the portion of the Net Profits
Interest relating to the abandoned property will be extinguished.
VOC Sponsor must maintain books and records sufficient to
determine the amounts payable for the Net Profits Interest to
the trust. Quarterly and annually, VOC Sponsor must deliver to
the trustee a statement of the computation of the net proceeds
for each computation period. The trustee has the right to
inspect and copy the books and records maintained by VOC Sponsor
during normal business hours and upon reasonable notice.
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DESCRIPTION
OF THE TRUST AGREEMENT
The following information and the information included under
Description of the trust units summarize the
material information contained in the trust agreement and the
conveyance. For more detailed provisions concerning the trust
and the conveyance, you should read the trust agreement and the
conveyance. Copies of the trust agreement and the conveyance
will be filed as exhibits to the registration statement. See
Where you can find more information.
CREATION
AND ORGANIZATION OF THE TRUST; AMENDMENTS
Immediately prior to the closing of this offering, VOC Sponsor
will contribute to the trust the term Net Profits Interest in
consideration of the receipt
of
trust units. The trusts first quarterly distribution will
consist of an amount in cash paid by VOC Sponsor equal to the
amount that would have been payable to the trust had the Net
Profits Interest been in effect during the period from
January 1, 2011 through June 30, 2011, less any
general and administrative expenses and reserves of the trust.
After the offering made hereby, VOC Sponsor will own its net
interests in the Underlying Properties subject to and burdened
by the Net Profits Interest.
The trust was created under Delaware law to acquire and hold the
Net Profits Interest for the benefit of the trust unitholders
pursuant to an agreement between VOC Sponsor, the trustee and
the Delaware trustee. The Net Profits Interest is passive in
nature and neither the trust nor the trustee has any control
over or responsibility for costs relating to the operation of
the properties comprising the Underlying Properties. Neither VOC
Sponsor nor other operators of the properties comprising the
Underlying Properties have any contractual commitments to the
trust to provide additional funding or to conduct further
drilling on or to maintain their ownership interest in any of
these properties. After the conveyance of the Net Profits
Interest, however, VOC Sponsor will retain an interest in each
of the Underlying Properties. For a description of the
Underlying Properties and other information relating to them,
see The Underlying Properties.
The trust agreement will provide that the trusts business
activities will be limited to owning the Net Profits Interest
and any activity reasonably related to such ownership, including
activities required or permitted by the terms of the conveyance
related to the Net Profits Interest. As a result, the trust will
not be permitted to acquire other oil and natural gas properties
or Net Profits Interests.
The beneficial interest in the trust is divided
into
trust units. Each of the trust units represents an equal
undivided beneficial interest in the assets of the trust. You
will find additional information concerning the trust units in
Description of the trust units.
Amendment of the trust agreement requires a vote of holders of a
majority of the outstanding trust units. However, no amendment
may:
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increase the power of the trustee or the Delaware trustee to
engage in business or investment activities; or
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alter the rights of the trust unitholders as among themselves.
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Certain amendments to the trust agreement do not require the
vote of the trust unitholders. The trustee may, without approval
of the trust unitholders, from time to time supplement or amend
the trust agreement in order to cure any ambiguity, to correct
or supplement any defective or inconsistent provisions, to grant
any benefit to all of the trust unitholders or to change the
name of the trust, provided such supplement or amendment is not
adverse to the interest of the trust unitholders. The business
and affairs of the trust will be managed by the trustee. VOC
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Sponsor has no ability to manage or influence the operations of
the trust. Likewise, the trust has no ability to manage or
influence the operation of VOC Sponsor.
ASSETS OF
THE TRUST
Upon completion of this offering, the assets of the trust will
consist of the Net Profits Interest and any cash and temporary
investments being held for the payment of expenses and
liabilities and for distribution to the trust unitholders.
DUTIES
AND POWERS OF THE TRUSTEE
The duties of the trustee are specified in the trust agreement
and by the laws of the state of Delaware, except as modified by
the trust agreement. The trustees principal duties consist
of:
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collecting cash attributable to the Net Profits Interest;
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paying expenses, charges and obligations of the trust from the
trusts assets;
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distributing distributable cash to the trust unitholders;
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causing to be prepared and distributed a tax information report
for each trust unitholder and to prepare and file tax returns on
behalf of the trust;
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causing to be prepared and filed reports required to be filed
under the Securities Exchange Act of 1934 and by the rules of
any securities exchange or quotation system on which the trust
units are listed or admitted to trading;
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establishing, evaluating and maintaining a system of internal
controls over financial reporting in compliance with the
requirements of Section 404 of the Sarbanes-Oxley Act of
2002;
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enforcing the rights under certain agreements entered into in
connection with this offering; and
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taking any action it deems necessary and advisable to best
achieve the purposes of the trust.
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In connection with the formation of the trust, the trustee
entered into several agreements with VOC Sponsor that impose
obligations upon VOC Sponsor that are enforceable by the trustee
on behalf of the trust. For example, when making decisions with
respect to the development, operation, abandonment or sale of
the Underlying Properties, VOC Sponsor is obligated under the
terms of the conveyance of the Net Profits Interest to use
commercially reasonable efforts to cause the operators of the
Underlying Properties to operate these properties as would a
reasonably prudent operator acting with respect to its own
properties (without regard to the existence of the Net Profits
Interest). In addition, the trust has entered into an
administrative services agreement with VOC Sponsor pursuant to
which VOC Sponsor has agreed to perform specified administrative
services on behalf of the trust in a good and workmanlike manner
in accordance with the sound and prudent practices of providers
of similar services. The trustee has the power and authority
under the trust agreement to enforce these agreements on behalf
of the trust.
The trustee may create a cash reserve to pay for future
liabilities of the trust. If the trustee determines that the
cash on hand and the cash to be received are, or are reasonably
likely to be, insufficient to cover the trusts
liabilities, the trustee may borrow funds to pay liabilities of
the
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trust. The trustee may borrow the funds from any person,
including itself or its affiliates. The trustee may also
mortgage the assets of the trust to secure payment of the
indebtedness. If the trust does not have sufficient cash to pay
future liabilities, it may, in limited circumstances, sell all
or a portion of the Net Profits Interest. The terms of such
indebtedness and security interest, if funds were loaned by the
entity serving as trustee or Delaware trustee or an affiliate
thereof, would be similar to the terms which such entity would
grant to a similarly situated commercial customer with whom it
did not have a fiduciary relationship, and such entity shall be
entitled to enforce its rights with respect to any such
indebtedness and security interest as if it were not then
serving as trustee or Delaware trustee. If the trustee borrows
funds, the trust unitholders will not receive distributions
until the borrowed funds are repaid. VOC Sponsor has agreed to
provide a letter of credit in the amount of $1.0 million to the
trustee to protect the trust against the risk that it does not
have sufficient cash to pay future liabilities.
Each quarter, the trustee will pay trust obligations and
expenses and distribute to the trust unitholders the remaining
proceeds received from the Net Profits Interest. The cash held
by the trustee as a reserve against future liabilities or for
distribution at the next distribution date must be invested in:
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interest bearing obligations of the United States government;
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money market funds that invest only in United States government
securities;
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repurchase agreements secured by interest-bearing obligations of
the United States government; or
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bank certificates of deposit.
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The trust may not acquire any asset except the Net Profits
Interest, cash and temporary cash investments, and it may not
engage in any investment activity except investing cash on hand.
The trust may merge or consolidate with or into one or more
limited partnerships, general partnerships, corporations,
business trusts, limited liability companies, or associations or
unincorporated businesses if such transaction is agreed to by
the trustee and by the affirmative vote of the holders of a
majority of the outstanding trust units and such transaction is
permitted under the Delaware Statutory Trust Act and any
other applicable law.
VOC Sponsor may request that the trustee sell all or a portion
of its Net Profits Interest under any of the following
circumstances:
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the sale does not involve a material part of the trusts
assets and is in the judgment of VOC sponsor in the best
interests of the trust unitholders; or
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the sale constitutes a material part of the trusts assets
and is in the best interests of the trust unitholders, subject
to the holders representing a majority of the outstanding trust
units approving the sale.
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The trustee will distribute the net proceeds from any sale of
the Net Profits Interest and other assets to the trust
unitholders.
Upon dissolution of the trust, the trustee must sell the Net
Profits Interest. No trust unitholder approval is required in
this event.
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The trustee may require any trust unitholder to dispose of his
trust units if an administrative or judicial proceeding seeks to
cancel or forfeit any of the property in which the trust holds
an interest because of the nationality or any other status of
that trust unitholder. If a trust unitholder fails to dispose of
his trust units, the trustee has the right to purchase them and
to borrow funds to make that purchase.
The trustee is not expected to maintain a website for filings
made by the trust with the SEC.
The trustee may agree to modifications of the terms of the
conveyance or to settle disputes involving the conveyance. The
trustee may not agree to modifications or settle disputes
involving the Net Profits Interest part of the conveyance if
these actions would change the character of the Net Profits
Interest in such a way that the Net Profits Interest becomes a
working interest or that the trust becomes an operating business.
LIABILITIES
OF THE TRUST
Because the trust does not conduct an active business and the
trustee has little power to incur obligations, it is expected
that the trust will only incur liabilities for routine
administrative expenses, such as the trustees fees,
accounting, engineering, legal, tax advisory and other
professional fees and other fees and expenses applicable to
public companies.
FEES AND
EXPENSES
The trust will be responsible for paying all legal, accounting,
tax advisory, engineering and stock exchange fees, printing
costs and other administrative and
out-of-pocket
expenses incurred by or at the direction of the trustee or the
Delaware trustee. The trust will also be responsible for paying
other expenses incurred as a result of being a publicly traded
entity, including costs associated with annual and quarterly
reports to unitholders, preparation of tax information material
and distribution, independent auditor fees and registrar and
transfer agent fees. These trust administrative expenses are
anticipated to aggregate approximately $900,000 for 2011.
Administrative expenses for subsequent years could be greater or
less depending on future events that cannot be predicted.
Included in the $900,000 annual estimate is an annual
administrative fee of $150,000 for the trustee and an annual
administrative fee of $2,500 for the Delaware trustee as well as
an annual administrative fee payable to VOC Sponsor, which fee
will total $75,000 in 2011 and will increase by 4% each year
beginning in January 2012. See The trust. The trust
will pay, out of the first cash payment received by the trust,
the trustees and Delaware trustees legal expenses
incurred in forming the trust as well as the Delaware
trustees acceptance fee in the amount of $4,000. These
costs will be deducted by the trust before distributions are
made to trust unitholders.
The fees described above are independent of the overhead fee
payable by Vess LLC on behalf of VOC Sponsor to VOC Operators
and the overhead reimbursement amount payable by VOC Sponsor to
Vess LLC. See VOC Sponsor Management of VOC
Sponsor.
FIDUCIARY
RESPONSIBILITY AND LIABILITY OF THE TRUSTEE
The trustee will not make business decisions affecting the
assets of the trust except to the extent it enforces its rights
under the conveyance agreement related to the Net Profits
Interest and the administrative services agreement described
above under Duties and powers of the
trustee that will be executed in connection with this
offering. Therefore, substantially all of the trustees
functions under the trust agreement are expected to be
ministerial in nature. See
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Duties and powers of the trustee above.
The trust agreement, however, provides that the trustee may:
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charge for its services as trustee;
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retain funds to pay for future expenses and deposit them with
one or more banks or financial institutions (which may include
the trustee to the extent permitted by law);
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lend funds at commercial rates to the trust to pay the
trusts expenses; and
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seek reimbursement from the trust for its
out-of-pocket
expenses.
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In discharging its duty to trust unitholders, the trustee may
act in its discretion and will be liable to the trust
unitholders only for its own fraud, gross negligence or acts or
omissions constituting fraud. The trustee will not be liable for
any act or omission of its agents or employees unless the
trustee acted in bad faith or with gross negligence in their
selection and retention. The trustee will be indemnified
individually or as the trustee for any liability or cost that it
incurs in the administration of the trust, except in cases of
fraud, gross negligence or bad faith. The trustee will have a
lien on the assets of the trust as security for this
indemnification and its compensation earned as trustee. Trust
unitholders will not be liable to the trustee for any
indemnification. See Description of the trust
units Liability of trust unitholders. The
trustee must ensure that all contractual liabilities of the
trust are limited to the assets of the trust and the trustee
will be liable for its failure to do so.
The trustee may consult with counsel, accountants, tax advisors,
geologists, engineers and other parties the trustee believes to
be qualified as experts on the matters for which advice is
sought. The trustee will be protected for any action it takes in
good faith reliance upon the opinion of the expert.
Except as expressly set forth in the trust agreement, neither
the trustee, the Delaware trustee nor the other indemnified
parties have any duties or liabilities, including fiduciary
duties, to the trust or any trust unitholder. The provisions of
the trust agreement, to the extent they restrict, eliminate or
otherwise modify the duties and liabilities, including fiduciary
duties of these persons otherwise existing at law or in equity,
are agreed by the trust unitholders to replace such other duties
and liabilities of these persons.
DURATION
OF THE TRUST; SALE OF THE NET PROFITS INTEREST
The Net Profits Interest will terminate on the later to occur of
(1) December 31, 2030, or (2) the time when
9.7 MMBoe have been produced from the Underlying Properties
and sold (which amount is the equivalent of 7.8 MMBoe in
respect of the trusts right to receive 80% of the net
proceeds from the Underlying Properties pursuant to the Net
Profits Interest), and the trust will wind up its affairs and
terminate. The trust will dissolve prior to its termination if:
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the trust sells the Net Profits Interest;
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annual cash available for distribution to the trust is less than
$1 million for each of two consecutive years;
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the holders of a majority of the outstanding trust units vote in
favor of dissolution; or
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the trust is judicially dissolved.
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The trustee would then sell all of the trusts assets,
either by private sale or public auction, and distribute the net
proceeds of the sale to the trust unitholders.
DISPUTE
RESOLUTION
Any dispute, controversy or claim that may arise between VOC
Sponsor and the trustee relating to the trust will be submitted
to binding arbitration before a tribunal of three arbitrators.
COMPENSATION
OF THE TRUSTEE AND THE DELAWARE TRUSTEE
The trustees and the Delaware trustees compensation
will be paid out of the trusts assets. See
Fees and expenses.
MISCELLANEOUS
The principal offices of the trustee are located at 919 Congress
Avenue, Suite 500, Austin, Texas 78701, and its telephone
number is
(512) 236-6599.
The Delaware trustee and the trustee may resign at any time or
be removed with or without cause at any time by a vote of not
less than a majority of the outstanding trust units. Any
successor must be a bank or trust company meeting certain
requirements including having combined capital, surplus and
undivided profits of at least $20,000,000, in the case of the
Delaware trustee, and $100,000,000, in the case of the trustee.
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DESCRIPTION
OF THE TRUST UNITS
Each trust unit is a unit of beneficial interest in the trust
and is entitled to receive cash distributions from the trust on
a pro rata basis. Each trust unitholder has the same rights
regarding each of his trust units as every other trust
unitholder has regarding his units. The trust units will be in
book-entry form only and will not be represented by
certificates. The trust will
have
trust units outstanding upon completion of this offering.
DISTRIBUTIONS
AND INCOME COMPUTATIONS
Each quarter, the trustee will determine the amount of funds
available for distribution to the trust unitholders. Available
funds are the excess cash, if any, received by the trust from
the Net Profits Interest and other sources (such as interest
earned on any amounts reserved by the trustee) that quarter,
over the trusts liabilities for that quarter. Available
funds will be reduced by any cash the trustee decides to hold as
a reserve against future liabilities. It is expected that
quarterly cash distributions during the term of the trust, other
than the first quarterly cash distribution, will be made by the
trustee on or about the 45th day following the end of each
quarter to the trust unitholders of record on the 30th day
following the end of each quarter (or the next succeeding
business day). The first distribution to trust unitholders
purchasing trust units in this offering will be made on or about
August 15, 2011 to trust unitholders owning trust units on
or about August 1, 2011.
Unless otherwise advised by counsel or the IRS, the trustee will
treat the income and expenses of the trust for each quarter as
belonging to the trust unitholders of record on the quarterly
record date. Trust unitholders will recognize income and
expenses for tax purposes in the quarter the trust receives or
pays those amounts, rather than in the quarter the trust
distributes them. Minor variances may occur. For example, the
trustee could establish a reserve in one quarter that would not
result in a tax deduction until a later quarter. The trustee
could also make a payment in one quarter that would be amortized
for tax purposes over several quarters. See Federal income
tax consequences.
TRANSFER
OF TRUST UNITS
Trust unitholders may transfer their trust units in accordance
with the trust agreement. The trustee will not require either
the transferor or transferee to pay a service charge for any
transfer of a trust unit. The trustee may require payment of any
tax or other governmental charge imposed for a transfer. The
trustee may treat the owner of any trust unit as shown by its
records as the owner of the trust unit. The trustee will not be
considered to know about any claim or demand on a trust unit by
any party except the record owner. A person who acquires a trust
unit after any quarterly record date will not be entitled to the
distribution relating to that quarterly record date. Delaware
law will govern all matters affecting the title, ownership or
transfer of trust units.
PERIODIC
REPORTS
The trustee will file all required trust federal and state
income tax and information returns. The trustee will prepare and
mail to trust unitholders annual reports that trust unitholders
need to correctly report their share of the income and
deductions of the trust. The trustee will also cause to be
prepared and filed reports required to be filed under the
Securities Exchange Act of 1934, as amended, and by the rules of
any securities exchange or quotation system on which the trust
units are listed or admitted to trading, and will also cause the
trust to comply with all of the provisions of the Sarbanes-Oxley
Act, including but not limited to, establishing, evaluating and
maintaining a system of internal controls over financial
reporting in compliance with the requirements of
Section 404 thereof.
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Each trust unitholder and his representatives may examine, for
any proper purpose, during reasonable business hours, the
records of the trust and the trustee.
LIABILITY
OF TRUST UNITHOLDERS
Under the Delaware Statutory Trust Act, trust unitholders
will be entitled to the same limitation of personal liability
extended to stockholders of private corporations for profit
under the General Corporation Law of the state of Delaware. No
assurance can be given, however, that the courts in
jurisdictions outside of Delaware will give effect to such
limitation.
VOTING
RIGHTS OF TRUST UNITHOLDERS
The trustee or trust unitholders owning at least 10% of the
outstanding trust units may call meetings of trust unitholders.
The trust will be responsible for all costs associated with
calling a meeting of trust unitholders unless such meeting is
called by the trust unitholders, in which case the trust
unitholders will be responsible for all costs associated with
calling such meeting of trust unitholders. Meetings must be held
in such location as is designated by the trustee in the notice
of such meeting. The trustee must send written notice of the
time and place of the meeting and the matters to be acted upon
to all of the trust unitholders at least 20 days and not
more than 60 days before the meeting. Trust unitholders
representing a majority of trust units outstanding must be
present or represented to have a quorum. Each trust unitholder
is entitled to one vote for each trust unit owned.
Unless otherwise required by the trust agreement, a matter may
be approved or disapproved by the vote of a majority of the
trust units held by the trust unitholders at a meeting where
there is a quorum. This is true, even if a majority of the total
trust units did not approve it. The affirmative vote of the
holders of a majority of the outstanding trust units is required
to:
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dissolve the trust;
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remove the trustee or the Delaware trustee;
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amend the trust agreement (except with respect to certain
matters that do not adversely affect the rights of trust
unitholders in any material respect);
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merge or consolidate the trust with or into another
entity; or
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approve the sale of all or any material part of the assets of
the trust.
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In addition, certain amendments to the trust agreement may be
made by the trustee without approval of the trust unitholders.
See Description of the trust agreement
Creation and organization of the trust; amendments. The
trustee must consent before all or any part of the trust assets
can be sold except in connection with the dissolution of the
trust or limited sales directed by VOC Sponsor in conjunction
with its sale of Underlying Properties.
COMPARISON
OF TRUST UNITS AND COMMON STOCK
Trust unitholders have more limited voting rights than those of
stockholders of most public corporations. For example, there is
no requirement for annual meetings of trust unitholders or for
annual or other periodic re-election of the trustee.
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You should also be aware of the following ways in which an
investment in trust units is different from an investment in
common stock of a corporation.
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Trust Units
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Common Stock
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Voting
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The trust agreement provides voting rights to trust unitholders
to remove and replace the trustee and to approve or disapprove
major trust transactions.
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Corporate statutes provide voting rights to stockholders to
elect directors and to approve or disapprove major corporate
transactions.
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Income Tax
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The trust is not subject to income tax; trust unitholders are
subject to income tax on their pro rata share of trust income,
gain, loss and deduction.
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Corporations are taxed on their income and their stockholders
are taxed on dividends.
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Distributions
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Substantially all of the cash receipts of the trust is required
to be distributed to trust unitholders.
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Stockholders receive dividends at the discretion of the board of
directors.
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Business and Assets
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The business of the trust is limited to specific assets with a
finite economic life.
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A corporation conducts an active business for an unlimited term
and can reinvest its earnings and raise additional capital to
expand.
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Fiduciary Duties
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The trustee shall not be liable to the trust unitholders for any
of its acts or omissions absent its own fraud, gross negligence
or bad faith.
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Officers and directors have a fiduciary duty of loyalty to
stockholders and a duty to use due care in management and
administration of a corporation.
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TRUST UNITS
ELIGIBLE FOR FUTURE SALE
GENERAL
Prior to this offering, there has been no public market for the
trust units. Sales of substantial amounts of the trust units in
the open market, or the perception that those sales could occur,
could adversely affect prevailing market prices.
Upon completion of this offering, there will be
outstanding
trust units. All of the trust units sold in this offering,
or
trust units if the underwriters exercise their option to
purchase additional trust units in full, will be freely tradable
without restriction under the Securities Act of 1933, as amended
(the Securities Act). All of the trust units
outstanding other than the trust units sold in this offering (a
total
of
trust units,
or
trust units if the underwriters exercise their option to
purchase additional trust units in full) will be
restricted securities within the meaning of
Rule 144 under the Securities Act and may not be sold other
than through registration under the Securities Act or pursuant
to an exemption from registration, subject to the restrictions
on transfer contained in the
lock-up
agreements described below and in Underwriting.
LOCK-UP
AGREEMENTS
In connection with this offering, VOC Sponsor and certain of its
affiliates, including VOC Partners, LLC, have agreed, for a
period of 180 days after the date of this prospectus, not
to offer, sell, contract to sell or otherwise dispose of or
transfer any trust units or any securities convertible into or
exchangeable for trust units without the prior written consent
of Raymond James & Associates, Inc., subject to
specified exceptions. See Underwriting for a
description of these
lock-up
arrangements. Upon the expiration of these
lock-up
agreements, trust
units,
or trust
units if the underwriters exercise their option to purchase
additional trust units in full, will be eligible for sale in the
public market under Rule 144 of the Securities Act, subject
to volume limitations and other restrictions contained in
Rule 144, or through registration under the Securities Act.
RULE 144
The trust units sold in the offering will generally be freely
transferable without restriction or further registration under
the Securities Act, except that any trust units owned by an
affiliate of the trust, including those held by VOC
Partners, LLC, 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 to be
sold into the market in an amount that does not exceed, during
any three-month period, the greater of:
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1.0% of the total number of the securities outstanding, or
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the average weekly reported trading volume of the trust units
for the four calendar weeks prior to the sale.
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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 the trust. A person who is not deemed to have been an
affiliate of VOC Sponsor or the trust at any time during the
three months preceding a sale, and who has beneficially owned
his trust units for at least six months (provided the trust is
in compliance with the current public information requirement)
or one year (regardless of whether the trust is in compliance
with the current public information requirement), would be
entitled to sell trust units under Rule 144 without regard
to
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the rules public information requirements, volume
limitations, manner of sale provisions and notice requirements.
REGISTRATION
RIGHTS
The trust intends to enter into a registration rights agreement
with VOC Partners, LLC in connection with the closing of this
offering. In the registration rights agreement, the trust will
agree to register the trust units it holds for the benefit of
VOC Partners, LLC. Specifically, the trust will agree:
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subject to the restrictions described above under
Lock-up
Agreements and under Underwriting
Lock-up
agreements, to use its reasonable best efforts to file a
registration statement, including, if so requested, a shelf
registration statement, with the SEC as promptly as practicable
following receipt of a notice requesting the filing of a
registration statement from holders representing a majority of
the then outstanding registrable trust units;
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to use its reasonable best efforts to cause the registration
statement or shelf registration statement to be declared
effective under the Securities Act as promptly as practicable
after the filing thereof; and
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to continuously maintain the effectiveness of the registration
statement under the Securities Act for 90 days (or for
three years if a shelf registration statement is requested)
after the effectiveness thereof or until the trust units covered
by the registration statement have been sold pursuant to such
registration statement or until all registrable trust units:
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have been sold pursuant to Rule 144 under the Securities
Act if the transferee thereof does not receive restricted
securities;
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have been sold in a private transaction in which the
transferors rights under the registration rights agreement
are not assigned to the transferee of the trust units; or
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become eligible for resale pursuant to Rule 144 (or any
similar rule then in effect under the Securities Act).
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VOC Partners, LLC will have the right to require the trust to
file no more than three registration statements in aggregate.
In connection with the preparation and filing of any
registration statement, VOC Sponsor will bear all costs and
expenses incidental to any registration statement, excluding
certain internal expenses of the trust, which will be borne by
the trust, and any underwriting discounts and commissions, which
will be borne by VOC Partners, LLC.
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FEDERAL
INCOME TAX CONSEQUENCES
U.S.
FEDERAL INCOME TAX CONSEQUENCES
The following is a discussion of the material U.S. federal
income tax considerations that may be relevant to prospective
trust unitholders and, unless otherwise noted in the following
discussion, expresses the opinion of Vinson & Elkins
L.L.P., insofar as it relates to matters of law and legal
conclusions. This section is based upon current provisions of
the Internal Revenue Code of 1986, as amended (the
Code), existing (and, to the extent noted, proposed)
Treasury regulations thereunder, and current administrative
rulings and court decisions, all of which are subject to change
or different interpretation at any time, possibly with
retroactive effect. Subsequent changes in such authorities may
cause the U.S. federal income tax consequences to vary
substantially from the consequences described below. No attempt
has been made in the following discussion to comment on all
U.S. federal income tax matters affecting the trust or the
trust unitholders.
The following discussion is limited to trust unitholders who
purchase the trust units upon the initial issuance at the
initial issue price (which will equal the first price at which a
substantial amount of trust units are sold to the public for
cash) and who hold the trust units as capital assets
(generally, property held for investment). All references to
trust unitholders (including U.S. trust
unitholders and
non-U.S. trust
unitholders) are to beneficial owners of the trust units. This
summary does not address the effect of the U.S. federal
estate or gift tax laws or the tax considerations arising under
the law of any state, local or
non-U.S. jurisdiction.
Moreover, the discussion has only limited application to trust
unitholders subject to specialized tax treatment such as,
without limitation:
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banks, insurance companies or other financial institutions;
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trust unitholders subject to the alternative minimum tax;
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tax-exempt organizations;
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dealers in securities or commodities;
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regulated investment companies;
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traders in securities that elect to use a
mark-to-market
method of accounting for their securities holdings;
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non-U.S. trust
unitholders (as defined below) that are controlled foreign
corporations or passive foreign investment
companies;
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persons that are S-corporations, partnerships or other
pass-through entities;
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persons that own their interest in the trust units through
S-corporations, partnerships or other pass-through entities;
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persons that at any time own more than 5% of the aggregate fair
market value of the trust units;
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expatriates and certain former citizens or long-term residents
of the United States;
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U.S. trust unitholders (as defined below) whose functional
currency is not the U.S. dollar;
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persons who hold the trust units as a position in a hedging
transaction, straddle, conversion
transaction or other risk reduction transaction; or
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persons deemed to sell the trust units under the constructive
sale provisions of the Code.
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Prospective investors are urged to consult their own tax
advisors as to the particular tax consequences to them of the
ownership and disposition of an investment in trust units,
including the applicability of any U.S. federal income,
federal estate or gift tax, state, local and foreign tax laws,
changes in applicable tax laws and any pending or proposed
legislation.
As used herein, the term U.S. trust unitholder
means a beneficial owner of trust units that for
U.S. federal income tax purposes is:
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an individual who is a citizen of the United States or who is a
resident of the United States for U.S. federal income
tax purposes,
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a corporation, or an entity treated as a corporation for
U.S. federal income tax purposes, created or organized in
or under the laws of the United States, a state thereof or the
District of Columbia,
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an estate the income of which is subject to U.S. federal
income taxation regardless of its source, or
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a trust if it is subject to the primary supervision of a
U.S. court and the control of one or more United States
persons (as defined for U.S. federal income tax purposes)
or that has a valid election in effect under applicable
U.S. Treasury regulations to be treated as a United States
person.
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The term
non-U.S. trust
unitholder means any beneficial owner of a trust unit,
other than an entity that is classified for U.S. federal
income tax purposes as a partnership, that is not a
U.S. trust unitholder.
If a partnership (including for this purpose any entity or
arrangement treated as a partnership for U.S. federal
income tax purposes) is a beneficial owner of trust units, the
tax treatment of a partner in the partnership will depend upon
the status of the partner and the activities of the partnership.
A trust unitholder that is a partnership, and the partners in
such partnership, should consult their own tax advisors about
the U.S. federal income tax consequences of purchasing,
owning, and disposing of trust units.
Classification
and Taxation of the Trust
In the opinion of Vinson & Elkins, L.L.P., for
U.S. federal income tax purposes, the trust will be treated
as a grantor trust and not as an unincorporated business entity.
As a grantor trust, the trust will not be subject to tax at the
trust level. Rather, the grantors, who in this case are the
trust unitholders, will be considered to own and receive the
trusts assets and income and will be directly taxable
thereon as though no trust were in existence.
No ruling has been or will be requested from the Internal
Revenue Service (IRS) with respect to the
U.S. federal income tax treatment of the trust, including a
ruling as to the status of the trust as a grantor trust or as a
partnership for U.S. federal income tax purposes. Thus, no
assurance can be provided that the opinions and statements set
forth in this discussion of U.S. federal income tax
consequences would be sustained by a court if contested by the
IRS.
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The remainder of the discussion below is based on
Vinson & Elkins L.L.P.s opinion that the trust
will be classified as a grantor trust for federal income tax
purposes.
Reporting
Requirements for Widely-Held Fixed Investment
Trusts
Under Treasury Regulations, the trust is classified as a
widely-held fixed investment trust. Those Treasury Regulations
require the sharing of tax information among trustees and
intermediaries that hold a trust interest on behalf of or for
the account of a beneficial owner or any representative or agent
of a trust interest holder of fixed investment trusts that are
classified as widely-held fixed investment trusts. These
reporting requirements provide for the dissemination of trust
tax information by the trustee to intermediaries who are
ultimately responsible for reporting the investor-specific
information through Form 1099 to the investors and the IRS.
Every trustee or intermediary that is required to file a
Form 1099 for a trust unitholder must furnish a written tax
information statement that is in support of the amounts as
reported on the applicable Form 1099 to the trust
unitholder. Any generic tax information provided by the trustee
of the trust is intended to be used only to assist trust
unitholders in the preparation of their federal and state income
tax returns.
Direct
Taxation of Trust Unitholders
Because the trust will be treated as a trust for
U.S. federal income tax purposes, trust unitholders will be
treated for such purposes as owning a direct interest in the
assets of the trust, and each trust unitholder will be taxed
directly on his pro rata share of the income and gain
attributable to the assets of the trust and will be entitled to
claim his pro rata share of the deductions and expenses
attributable to the assets of the trust (subject to certain
limitations discussed below). Information returns will be filed
as required by the widely held fixed investment trust rules,
reporting to the trust unitholders all items of income, gain,
loss, deduction and credit, which will be allocated based on
record ownership on the quarterly record dates and must be
included in the tax returns of the trust unitholders. Income,
gain, loss, deduction and credits attributable to the assets of
the trust will be taken into account by trust unitholders
consistent with their method of accounting and without regard to
the taxable year or accounting method employed by the trust.
Following the end of each quarter, the trustee will determine
the amount of funds available as of the end of such quarter for
distribution to the trust unitholders and will make
distributions of available funds, if any, to the unitholders on
or about the 45th day of the month following the end of the
quarter to the unitholders of record on the last business day of
such quarter. In certain circumstances, however, a trust
unitholder will not receive the distribution attributable to
such income. For example, if the trustee establishes a reserve
or borrows money to satisfy liabilities of the trust, income
associated with the cash used to establish that reserve or to
repay that loan must be reported by the trust unitholder, even
though that cash is not distributed to him.
As described above, the trust will allocate items of income,
gain, loss, deductions and credits to trust unitholders based on
record ownership on the quarterly record dates. It is possible
that the IRS could disagree with this allocation method and
could assert that income and deductions of the trust should be
determined and allocated on a daily or prorated basis, which
could require adjustments to the tax returns of the unitholders
affected by the issue and result in an increase in the
administrative expense of the trust in subsequent periods.
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
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long-term capital gains (generally, capital gains on certain
assets held for more than 12 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.
The recently enacted Health Care and Education Reconciliation
Act of 2010 will impose a 3.8% Medicare tax on certain
investment income earned by individuals and certain estates and
trusts for taxable years beginning after December 31, 2012.
For these purposes, investment income would generally include
interest income derived from investments such as the trust units
and gain realized by a trust unitholder from a sale of trust
units. In the case of an individual, the tax will be imposed on
the lesser of (i) the trust unitholders net income
from all investments, and (ii) the amount by which the
trust unitholders modified adjusted gross income exceeds
$250,000 (if the trust unitholder is married and filing jointly
or a surviving spouse) or $200,000 (if the trust unitholder is
not married). In the case of an estate or trust, the tax will be
imposed on the lesser of (1) undistributed net investment
income, or (2) the excess adjusted gross income over the
dollar amount at which the highest income tax bracket applicable
to an estate or trust begins.
Classification
of the Net Profits Interest
Based on representations made by VOC Sponsor regarding the
expected economic life of the Underlying Properties and the
expected duration of the Net Profits Interest, the Net Profits
Interest should be treated as a production payment
under Section 636 of the Code or otherwise as a debt
instrument for U.S. federal income tax purposes. Thus, each
trust unitholder should be treated as making a loan on the
Underlying Properties to VOC Sponsor in an aggregate amount
generally equal to the purchase price of the trust units (less
an amount equal to the distribution attributable to the period
from January 1, 2011 through June 30, 2011) and
proceeds payable to the trust from the sale of production from
the burdened properties (after June 30, 2011) should
be treated as payments of principal and interest on a debt
instrument issued by VOC Sponsor.
VOC Sponsor and the trust will treat the Net Profits Interest as
indebtedness subject to the Treasury Regulations applicable to
contingent payment debt instruments (the CPDI
regulations), and by purchasing trust units, each trust
unitholder will agree to be bound by VOC Sponsors
application of the CPDI regulations, including its determination
of the rate at which interest will be deemed to accrue on the
Net Profits Interest (treated as a debt instrument for
U.S. federal income tax purposes). The remainder of this
discussion assumes that the Net Profits Interest will be treated
in accordance with that agreement and VOC Sponsors
determinations. No assurance can be given that the IRS will not
assert that the Net Profits Interest should be treated
differently. Such different treatment could affect the amount,
timing and character of income, gain or loss in respect of an
investment in trust units and could require a trust unitholder
to accrue interest income at a rate different than the
comparable yield described below.
The portion of the purchase price of the trust units
attributable to the right to receive a distribution based on
production from the Underlying Properties for the period
commencing January 1, 2011 and ending on June 30, 2011
will be treated as a tax-free return of capital when such
distribution is received.
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TAX
CONSEQUENCES TO U.S. TRUST UNITHOLDERS
Tax
Treatment of Net Profits Interest
Under the CPDI regulations, a trust unitholder generally will be
required to accrue income on the Net Profits Interest in the
amounts described below, regardless of whether the
U.S. trust unitholder uses the cash or accrual method of
tax accounting.
The CPDI regulations provide that a U.S. trust unitholder
must accrue an amount of ordinary interest income for
U.S. federal income tax purposes, for each accrual period
prior to and including the maturity date of the debt instrument
that equals:
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the product of (i) the adjusted issue price (as defined
below) of the debt instrument represented by ownership of trust
units as of the beginning of the accrual period; and
(ii) the comparable yield to maturity (as defined below) of
such debt instrument, adjusted for the length of the accrual
period;
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divided by the number of days in the accrual period; and
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multiplied by the number of days during the accrual period that
the trust unitholder held the trust units.
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The issue price of the debt instrument held by the
trust is the first price at which a substantial amount of the
trust units is sold to the public excluding sales to bond
houses, brokers or similar persons or organizations acting in
the capacity of underwriters, placement agents or wholesalers.
The adjusted issue price of such a debt instrument
is its issue price increased by any interest income previously
accrued, determined without regard to any adjustments to
interest accruals described below, and decreased by the
projected amount of any payments scheduled to be made with
respect to the debt instrument at an earlier time. Under the
CPDI regulations, VOC Brazos is required to establish the
comparable yield for the debt instrument represented by
ownership of the trust units. The term comparable
yield means the annual yield VOC Brazos would be expected
to pay, as of the initial issue date, on a fixed rate debt
security with no contingent payments but with terms and
conditions otherwise comparable to those of the debt instrument
represented by ownership of trust units.
VOC Brazos intends to take the position that the comparable
yield for the debt instrument held by the trust is an annual
rate of %, compounded
semi-annually. The CPDI regulations require that the trust
provide to trust unitholders, solely for determining the amount
of interest accruals for U.S. federal income tax purposes,
a schedule of the projected amounts of payments, which are
referred to as projected payments, on the debt instrument held
by the trust. These payments set forth on the schedule must
produce a total return on such debt instrument equal to its
comparable yield. Amounts treated as interest under the CPDI
regulations are treated as original issue discount for all
purposes of the Code.
As required by the CPDI regulations, for U.S. federal
income tax purposes, each holder of trust units must use the
comparable yield and the schedule of projected payments as
described above in determining its interest accruals, and the
adjustments thereto described below, in respect of the debt
instrument held by the trust. You may obtain the projected
payment schedule by submitting a written request for such
information to VOC Brazos at 1700 Waterfront Parkway, Building
500, Wichita, Kansas 67206, Attention: Chief Financial Officer.
Our determinations of the comparable yield and the projected
payment schedule are not binding on the IRS and it could
challenge such determinations. If it did so, and if any such
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challenge were successful, then the amount and timing of
interest income accruals of the trust unitholders would be
different from those reported by us or included on previously
filed tax returns by the trust unitholders.
The comparable yield and the schedule of projected payments are
not determined for any purpose other than for the determination
for U.S. federal income tax purposes of a trust
unitholders interest accruals and adjustments thereof in
respect of the debt instrument represented by ownership of trust
units and do not constitute a projection or representation
regarding the actual amounts payable on the trust units.
If, during any taxable year, the trust receives actual payments
with respect to the debt instrument held by the trust that in
the aggregate exceed the total amount of projected payments for
that taxable year, the trust will incur a net positive
adjustment under the CPDI regulations equal to the amount
of such excess. The trust will treat a net positive
adjustment as additional ordinary interest income for that
taxable year.
If the trust receives in a taxable year actual payments with
respect to the debt instrument held by the trust that in the
aggregate are less than the amount of projected payments for
that taxable year, the trust will incur a net negative
adjustment under the CPDI regulations equal to the amount
of such deficit. This adjustment will (a) first reduce the
trusts interest income on the debt instrument held by the
trust for that taxable year, and (b) to the extent of any
excess after the application of (a) give rise to an
ordinary loss to the extent of the trusts interest income
on such debt instrument during prior taxable years, reduced to
the extent such interest was offset by prior net negative
adjustments. Any negative adjustment in excess of the amount
described in (a) and (b) will be carried forward, as a
negative adjustment to offset future interest income in respect
of the debt instrument held by the trust or to reduce the amount
realized on a sale, exchange, conversion or retirement of such
debt instrument.
Neither the trust nor the trust unitholders are entitled to
claim depletion deductions with respect to the burdened
properties.
If the Net Profits Interest is not treated as a debt instrument,
a trust unitholder would be allowed to recoup its basis in the
Net Profits Interest on a schedule that is in proportion to
expected production from the Net Profits Interest, with the
effect that a trust unitholder would be entitled to deductions
in respect of basis recovery on a schedule that is more
favorable compared to the trust unitholders entitlement to
treat a portion of its receipts as return of principal if the
Net Profits Interest is treated, in accordance with tax
counsels opinion, as a debt instrument. In that case,
however, the deductions so allowed may be itemized deductions,
the deductibility of which would be subject to limitations that
disallow itemized deductions that are less than 2% of a
taxpayers adjusted gross income, or reduce the amount of
itemized deductions that are otherwise allowable by the lesser
of (i) 3% of (A) adjusted gross income over
(B) $100,000 ($50,000 in the case of a separate return by a
married individual), subject to adjustment for inflation and
(ii) 80% of the amount of itemized deductions that are
otherwise allowable, or both. Although the matter is not free
from doubt, tax counsel believes that, if the issue became
relevant as a result of the classification of the Net Profits
Interest as other than a debt instrument, deductions in respect
of basis recovery should not be itemized deductions, as the
deductions should, under Section 62(a)(4) of the Code, be
considered deductions that are attributable to property held for
the production of royalty income.
Disposition
of Trust Units
For U.S. federal income tax purposes, a sale of trust units
will be treated as a sale by the U.S. trust unitholder of
his interest in the assets of the trust. Generally, a
U.S. trust unitholder
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will recognize gain or loss on a sale or exchange of trust units
equal to the difference between the amount realized and the
U.S. trust unitholders adjusted tax basis for the
trust units sold. A U.S. trust unitholders adjusted
tax basis in his trust units will be equal to the
U.S. trust unitholders original purchase price for
the trust units, increased by any interest income previously
accrued by the U.S. trust unitholder (determined without
regard to any adjustments to interest accruals for positive or
negative adjustments as described above) and decreased by the
amount of any projected payments that have been previously
scheduled to be made in respect of the trust units (without
regard to the actual amount paid).
Under the CPDI regulations, gain recognized upon a sale or
exchange of a trust unit attributable to the Net Profits
Interest (the amount of which is reduced by any unused
adjustments as discussed above) will generally be treated as
ordinary interest income. Any loss will be ordinary loss to the
extent of interest previously included in income (reduced by any
negative adjustments thereto), and thereafter, capital loss
(which will be long-term if the trust unit is held for more than
one year). Net capital loss may offset no more than $3,000 of
ordinary income in the case of individuals and may only be used
to offset capital gain in the case of corporations.
Trust Administrative
Expenses
Expenses of the trust will include administrative expenses of
the trustee. As discussed above, certain miscellaneous itemized
deductions may generally be subject to limitations on
deductibility. Under these rules, administrative expenses
attributable to the trust units are miscellaneous itemized
deductions that generally will have to be aggregated with an
individual unitholders other miscellaneous itemized
deductions to determine the excess over 2% of adjusted gross
income. It is anticipated that the amount of such administrative
expenses will not be significant in relation to the trusts
income.
Backup
Withholding and Information Reporting
Payments of principal and interest on, and the proceeds of
dispositions of, the trust units, may be subject to information
reporting and U.S. federal backup withholding tax if the
trust unitholder thereof fails to supply an accurate taxpayer
identification number or otherwise fails to comply with
applicable U.S. information reporting or certification
requirements. Any amounts so withheld will be allowed as a
credit against the trust unitholders U.S. federal
income tax liability and may entitle the trust unitholder to a
refund, provided that the required information is timely
furnished to the IRS.
TAX
CONSEQUENCES TO
NON-U.S.
TRUST UNITHOLDERS
The following is a summary of certain material U.S. federal
income tax consequences that will apply to you if you are a
non-U.S. trust
unitholder.
Non-U.S. trust
unitholders should consult their own independent tax advisors to
determine the U.S. federal, state, local and foreign tax
consequences that may be relevant to them.
Payments
with Respect to the Trust Units
Interest paid with respect to the Net Profits Interest will be
treated as interest, the amount of which is
contingent on the earnings of VOC Sponsor, and thus
will not qualify for the portfolio interest
exemption under Sections 871 and 881 of the Code. As
a result, such interest will be subject to U.S. federal
withholding tax at a 30 percent rate unless the
non-U.S. trust
unitholder is eligible for a lower rate under an applicable
income tax treaty or the interest is effectively connected with
the
non-U.S. trust
unitholders conduct of a trade or business in the
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United States, and in either case, the
non-U.S. trust
unitholder provides appropriate certification. A
non-U.S. trust
unitholder generally can meet the certification requirement by
providing an IRS
Form W-8BEN
(in the case of a claim of treaty benefits) or a
W-8 ECI
(with respect to the
non-U.S. trust
unitholders conduct of a U.S. trade or business).
If a
non-U.S. trust
unitholder is engaged in a trade or business in the United
States, and if payments on or gain realized on a sale or other
disposition of a trust unit are effectively connected with the
conduct of this trade or business, the
non-U.S. trust
unitholder, although exempt from U.S. withholding tax (if
the appropriate certification is furnished), will generally be
taxed in the same manner as a U.S. trust unitholder (see
Tax consequences to U.S. trust
unitholders above). Any such
non-U.S. trust
unitholder should consult its own tax advisers with respect to
other tax consequences of the ownership of the trust units,
including the possible imposition of a 30% branch profits tax in
the case of a
non-U.S. trust
unitholder that is classified for federal income tax purposes as
a corporation.
Sale
or Exchange of Trust Units
The Net Profits Interest will be treated as United States
real property interests for U.S. federal income tax
purposes. However, as long as the trust units are regularly
traded on an established securities market, gain realized by a
non-U.S. trust
unitholder on a sale of trust units will be subject to federal
income tax only if:
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the gain is, or is treated as, effectively connected with
business conducted by the
non-U.S. trust
unitholder in the United States, and in the case of an
applicable tax treaty, is attributable to a U.S. permanent
establishment maintained by the
non-U.S. trust
unitholder;
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the
non-U.S. trust
unitholder is an individual who is present in the United States
for at least 183 days in the year of the sale; or
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the
non-U.S. trust
unitholder owns currently or owned at certain earlier times
directly or by applying certain attribution rules, more than 5%
of the trusts units.
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A
non-U.S. trust
unitholder will be subject to U.S. federal income tax on
any gain allocable to the
non-U.S. trust
unitholder upon the sale by the trust of all or any part of the
Net Profits Interest, and distributions to the
non-U.S. trust
unitholder will be subject to withholding of U.S. tax
(currently at the rate of 35%) to the extent the distributions
are attributable to such gains.
Backup
Withholding Tax and Information Reporting
Payments to
non-U.S. trust
unitholders of interest, and amounts withheld from such
payments, if any, generally will be required to be reported to
the IRS and to the
non-U.S. trust
unitholder.
A
non-U.S. trust
unitholder may be subject to backup withholding tax, currently
at a rate of 28%, with respect to payments from the trust and
the proceeds from dispositions of trust units, unless such
non-U.S. trust
unitholder complies with certain certification requirements
(usually satisfied by providing a duly completed IRS
Form W-8BEN)
or otherwise establishes an exemption. Backup withholding is not
an additional tax. Any amounts withheld under the backup
withholding rules will be allowed as a refund or a credit
against a
non-U.S. trust
unitholders U.S. federal income tax liability,
provided certain required information is provided to the IRS.
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Payments of the proceeds of a sale of a trust unit effected by
the U.S. office of a U.S. or foreign broker will be
subject to information reporting requirements and backup
withholding unless the
non-U.S. trust
unitholder properly certifies under penalties of perjury as to
its foreign status and certain other conditions are met or the
non-U.S. trust
unitholder otherwise establishes an exemption. Information
reporting requirements and backup withholding generally will not
apply to any payment of the proceeds of the sale of a trust unit
effected outside of the United States by a foreign office of a
broker. However, unless such a broker has documentary evidence
in its records that the holder is a
non-U.S. trust
unitholder and certain other conditions are met, or the
non-U.S. trust
unitholder otherwise establishes an exemption, information
reporting will apply to a payment of the proceeds of the sale of
a trust unit effected outside the United States by such a broker
if it:
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is a United States person;
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derives 50% or more of its gross income for certain periods from
the conduct of a trade or business in the United States;
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is a controlled foreign corporation for U.S. federal income
tax purposes; or
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is a foreign partnership that, at any time during its taxable
year, has more than 50% of its income or capital interests owned
by United States persons or is engaged in the conduct of a
U.S. trade or business.
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Any amount withheld under the backup withholding rules may be
credited against the
non-U.S. trust
unitholders U.S. federal income tax liability and any
excess may be refundable if the proper information is provided
to the IRS.
CONSEQUENCES
TO TAX EXEMPT ORGANIZATIONS
Employee benefit plans and most other organizations exempt from
U.S. federal income tax including IRAs and other retirement
plans are subject to U.S. federal income tax on unrelated
business taxable income. Because the trusts income is not
expected to be unrelated business taxable income, such a
tax-exempt organization is not expected to be taxed on income
generated by ownership of trust units so long as neither the
property held by the trust nor the trust units are treated as
debt-financed property within the meaning of Section 514(b)
of the Code. In general, trust property would be debt-financed
if the trust incurs debt to acquire the property or otherwise
incurs or maintains a debt that would not have been incurred or
maintained if the property had not been acquired and a trust
unit would be debt-financed if the trust unitholder incurs debt
to acquire the trust unit or otherwise incurs or maintains a
debt that would not have been incurred or maintained if the
trust unit had not been acquired.
PROSPECTIVE INVESTORS IN TRUST UNITS ARE STRONGLY
ENCOURAGED TO CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THE
TAX CONSEQUENCES TO THEM OF THE PURCHASE, OWNERSHIP AND
DISPOSITION OF THE TRUST UNITS IN LIGHT OF THEIR OWN
PARTICULAR CIRCUMSTANCES, INCLUDING THE TAX CONSEQUENCES UNDER
STATE, LOCAL, FOREIGN AND OTHER TAX LAWS AND THE POSSIBLE
EFFECTS OF CHANGES IN UNITED STATES FEDERAL OR OTHER TAX LAWS.
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STATE TAX
CONSIDERATIONS
The following is intended as a brief summary of certain
information regarding state income taxes and other state tax
matters affecting individuals who are trust unitholders.
Unitholders are urged to consult their own legal and tax
advisors with respect to these matters.
Prospective investors should consider state and local tax
consequences of an investment in the trust units. The trust will
own the Net Profits Interest burdening specified oil and natural
gas properties located in the states of Kansas and Texas. Kansas
currently imposes a personal income tax on individuals, but
Texas currently does not.
Kansas income tax law generally conforms to the federal income
tax laws, meaning that for Kansas income tax purposes, the trust
should be treated as a grantor trust, a trust unitholder should
be considered to own and receive his or her share of the
trusts assets and income, and the Net Profits Interest
should be treated as a debt instrument. If treated as owning a
debt instrument through a grantor trust, an individual trust
unitholder who is a nonresident of Kansas generally will not be
subject to Kansas income tax on his share of the trusts
income, except to the extent the trust units are employed by
such trust unitholder in a trade, business, profession or
occupation carried on in Kansas. In general, an individual trust
unitholder will not be deemed to carry on a trade, business,
profession or occupation in Kansas solely by reason of the
purchase and sale of trust units for such nonresidents own
account as an investor. An individual trust unitholder who is a
resident of Kansas will be subject to Kansas income tax on his
share of the trusts income. The trust should not be
required to withhold Kansas income tax from distributions made
to an individual resident or nonresident trust unitholder as
long as the trust is taxed as a grantor trust, and the Net
Profits Interest is treated as a debt instrument, for federal
income tax purposes.
The trust units may constitute real property or an interest in
real property under the inheritance, estate and probate laws of
the states listed above.
110
ERISA
CONSIDERATIONS
The Employee Retirement Income Security Act of 1974, as amended,
regulates pension, profit-sharing and other employee benefit
plans to which it applies. ERISA also contains standards for
persons who are fiduciaries of those plans. In addition, the
Internal Revenue Code provides similar requirements and
standards which are applicable to qualified plans, which include
these types of plans, and to individual retirement accounts,
whether or not subject to ERISA.
A fiduciary of an employee benefit plan should carefully
consider fiduciary standards under ERISA regarding the
plans particular circumstances before authorizing an
investment in trust units. A fiduciary should consider:
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whether the investment satisfies the prudence requirements of
Section 404(a)(1)(B) of ERISA;
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whether the investment satisfies the diversification
requirements of Section 404(a)(1)(C) of ERISA; and
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whether the investment is in accordance with the documents and
instruments governing the plan as required by
Section 404(a)(1)(D) of ERISA.
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A fiduciary should also consider whether an investment in trust
units might result in direct or indirect nonexempt prohibited
transactions under Section 406 of ERISA and Internal
Revenue Code Section 4975. In deciding whether an
investment involves a prohibited transaction, a fiduciary must
determine whether there are plan assets in the transaction. The
Department of Labor has published final regulations concerning
whether or not an employee benefit plans assets would be
deemed to include an interest in the underlying assets of an
entity for purposes of the reporting, disclosure and fiduciary
responsibility provisions of ERISA and analogous provisions of
the Internal Revenue Code. These regulations provide that the
underlying assets of an entity will not be considered plan
assets if the equity interests in the entity are a
publicly offered security. VOC Sponsor expects that at the time
of the sale of the trust units in this offering, they will be
publicly offered securities. Fiduciaries, however, will need to
determine whether the acquisition of trust units is a nonexempt
prohibited transaction under the general requirements of ERISA
Section 406 and Internal Revenue Code Section 4975.
The prohibited transaction rules are complex, and persons
involved in prohibited transactions are subject to penalties.
For that reason, potential employee benefit plan investors
should consult with their counsel to determine the consequences
under ERISA and the Internal Revenue Code of their acquisition
and ownership of trust units.
111
SELLING
TRUST UNITHOLDER
Immediately prior to the closing of the offering made hereby,
VOC Sponsor will convey to the trust the Net Profits Interest in
exchange
for
trust units. Of those trust
units, are
being offered hereby
and
are subject
to
purchase by the underwriters pursuant to their
30-day
option to purchase additional trust units. Further, VOC Sponsor
has agreed to sell to VOC Partners, LLC, an affiliate of
VOC Sponsor, all remaining trust units it holds no later
than 45 days after the closing of the offering made hereby.
VOC Sponsor and VOC Partners, LLC have agreed not to sell any of
such trust units for a period of 180 days after the date of
this prospectus without the prior written consent of Raymond
James & Associates, Inc., acting as representative of
the several underwriters. See Underwriting.
The following table provides information regarding the selling
trust unitholders ownership of the trust units.
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Ownership of Trust
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Number of
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Ownership of Trust
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Units Before Offering
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Trust Units
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Units After Offering (1)
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Selling Trust Unitholders
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Number
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Percentage
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Being Offered
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Number
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Percentage
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VOC Sponsor
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100
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%
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(1)
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Gives effect to the sale of trust
units to VOC Partners, LLC 45 days following the closing of
the offering.
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Prior to this offering, there has been no public market for the
trust units. Therefore, if VOC Partners, LLC disposes all or a
portion of the trust units acquired from VOC Sponsor pursuant to
the Unit Purchase Agreement, the effect of such disposal on
future market prices, if any, of market sales of such remaining
trust units or the availability of trust units for sale cannot
be predicted. Nevertheless, sales of substantial amounts of
trust units in the public market could adversely affect future
market prices.
112
UNDERWRITING
Subject to the terms and conditions in an underwriting agreement
dated ,
2011, the underwriters named below, for whom Raymond
James & Associates, Inc., is acting as representative,
have severally agreed to purchase from VOC Sponsor the number of
trust units set forth opposite their names:
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Number of
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Underwriter
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Trust Units
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Raymond James & Associates, Inc.
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Total
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The underwriting agreement provides that the obligations of the
underwriters to purchase and accept delivery of the trust units
offered by this prospectus are subject to approval by their
counsel of legal matters and to other conditions set forth in
the underwriting agreement. The underwriters are obligated to
purchase and accept delivery of all of the trust units offered
by this prospectus if any of the units are purchased, other than
those covered by the option to purchase additional trust units
described below.
The underwriters propose to offer the trust units directly to
the public at the public offering price indicated on the cover
page of this prospectus and to various dealers at that price
less a concession not in excess of
$ per unit. If all of the trust
units are not sold at the public offering price, the
underwriters may change the public offering price and other
selling terms. The trust units are offered by the underwriters
as stated in this prospectus, subject to receipt and acceptance
by them. The underwriters reserve the right to reject an order
for the purchase of the trust units in whole or in part.
OPTION TO
PURCHASE ADDITIONAL TRUST UNITS
VOC Sponsor has granted the underwriters an option, exercisable
for 30 days after the date of this prospectus, to purchase
from time to time up to an aggregate
of
additional trust units to cover over-allotments, if any, at the
public offering price less the underwriting discounts and
commissions set forth on the cover page of this prospectus. If
the underwriters exercise this option, each underwriter, subject
to certain conditions, will become obligated to purchase its pro
rata portion of these additional units based on the
underwriters percentage purchase commitment in this
offering as indicated in the table above. The underwriters may
exercise the option to purchase additional trust units only to
cover over-allotments made in connection with the sale of the
trust units offered in this offering.
DISCOUNTS
AND EXPENSES
The following table shows the amount per unit and total
underwriting discounts and commissions VOC Sponsor will pay to
the underwriters (dollars in thousands, except per unit). The
amounts are shown assuming both no exercise and full exercise of
the underwriters option to purchase additional trust units.
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Per Unit
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No Exercise
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Full Exercise
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Public offering price
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$
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$
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$
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Underwriting discounts and commissions
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Proceeds, before expenses, to VOC Sponsor
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113
VOC Sponsor will pay Raymond James & Associates, Inc.
a structuring fee of $ (or
$ if the underwriters exercise
their option to purchase additional trust units) for evaluation,
analysis and structuring of the trust.
The expenses of this offering that are payable by VOC Sponsor
are estimated to be $ (exclusive of underwriting discounts,
commissions and structuring fees). In no event will the maximum
amount of compensation to be paid to members of the Financial
Industry Regulatory Authority, Inc., or FINRA, in
connection with this offering exceed 10% plus 0.5% for bona fide
due diligence expenses.
INDEMNIFICATION
VOC Sponsor has agreed to indemnify the underwriters and persons
who control the underwriters against certain liabilities that
may arise in connection with this offering, including
liabilities under the Securities Act and liabilities arising
from breaches of representations and warranties contained in the
underwriting agreement.
LOCK-UP
AGREEMENTS
Subject to specified exceptions, VOC Sponsor and certain of its
affiliates including VOC Partners, LLC, have agreed with the
underwriters, for a period of 180 days after the date of
this prospectus, without the prior written consent of Raymond
James & Associates, Inc.:
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not to offer, sell, contract to sell, announce the intention to
sell or pledge any of the trust units;
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not to grant or sell any option or contract to purchase any of
the trust units;
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not to enter into any swap or other agreement that transfers any
of the economic consequences of ownership of or otherwise
transfer or dispose of, directly or indirectly, any of the trust
units; and
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not to enter into any hedging, collar or other transaction or
arrangement that is designed or reasonably expected to lead to
or result in a transfer, in whole or in part, of any of the
economic consequences of ownership of the trust units, whether
or not such transfer would be for any consideration.
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These agreements also prohibit such persons from entering into
any of the foregoing transactions with respect to any securities
that are convertible into or exchangeable for the trust units.
Raymond James & Associates, Inc. may, in its
discretion and at any time without notice, release all or any
portion of the securities subject to these agreements. Raymond
James & Associates, Inc. does not have any present
intent or any understanding to release all or any portion of the
securities subject to these agreements.
The 180-day
period described in the preceding paragraphs will be extended if:
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during the last 17 days of the
180-day
period, the trust issues a release concerning earnings or
announces material news or a material event relating to the
trust occurs; or
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prior to the expiration of the
180-day
period, the trust announces that it will release distributable
cash during the
16-day
period beginning on the last day of the
180-day
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114
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period, in which case the restrictions described in the
preceding paragraphs will continue to apply until the expiration
of the
18-day
period beginning on the issuance of the earnings release, the
announcement of the material news or the occurrence of the
material event.
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STABILIZATION
Until this offering is completed, rules of the SEC may limit the
ability of the underwriters and various selling group members to
bid for and purchase the trust units. As an exception to these
rules, the underwriters may engage in activities that stabilize,
maintain or otherwise affect the price of the trust units,
including:
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short sales,
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syndicate covering transactions,
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imposition of penalty bids, and
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purchases to cover positions created by short sales.
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Stabilizing transactions consist of bids or purchases made for
the purpose of preventing or retarding a decline in the market
price of the trust units while this offering is in progress.
Stabilizing transactions may include making short sales of trust
units, which involve the sale by the underwriter of a greater
number of trust units than it is required to purchase in this
offering and purchasing trust units from VOC Sponsor or in the
open market to cover positions created by short sales. Short
sales may be covered shorts, which are short
positions in an amount not greater than the underwriters
option to purchase additional trust units referred to above, or
may be naked shorts, which are short positions in
excess of that amount.
Each underwriter may close out any covered short position either
by exercising its option to purchase additional trust units, in
whole or in part, or by purchasing trust units in the open
market. In making this determination, each underwriter will
consider, among other things, the price of trust units available
for purchase in the open market compared to the price at which
the underwriter may purchase trust units pursuant to the option
to purchase additional trust units.
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 trust units in the open market that could
adversely affect investors who purchased in this offering. To
the extent that the underwriters create a naked short position,
they will purchase trust units in the open market to cover the
position.
The underwriters also may impose a penalty bid on selling group
members. This means that if the underwriters purchase trust
units in the open market in stabilizing transactions or to cover
short sales, the underwriters can require the selling group
members that sold those trust units as part of this offering to
repay the selling concession received by them.
As a result of these activities, the price of the trust units
may be higher than the price that otherwise might exist in the
open market. If the underwriters commence these activities, they
may discontinue them without notice at any time. The
underwriters may carry out these transactions on the New York
Stock Exchange or otherwise.
115
DISCRETIONARY
ACCOUNTS
The underwriters may confirm sales of the trust units offered by
this prospectus to accounts over which they exercise
discretionary authority but do not expect those sales to exceed
5% of the total trust units offered by this prospectus.
LISTING
The trust intends to apply to have the units approved for
listing on the New York Stock Exchange under the symbol
VOC. In connection with the listing of the trust
units on the New York Stock Exchange, the underwriters will
undertake to sell round lots of 100 units or more to a
minimum of 400 beneficial owners.
IPO
PRICING
Prior to this offering, there has been no public market for the
trust units. Consequently, the initial public offering price for
the trust units will be determined by negotiations among VOC
Sponsor and the underwriters. The primary factors to be
considered in determining the initial public offering price will
be:
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estimates of distributions to trust unitholders,
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overall quality of the oil and natural gas properties
attributable to the Underlying Properties,
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industry and market conditions prevalent in the energy industry,
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the information set forth in this prospectus and otherwise
available to the representatives; and
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the general conditions of the securities markets at the time of
this offering.
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ELECTRONIC
PROSPECTUS
A prospectus in electronic format may be available on the
Internet sites or through other online services maintained by
one or more of the underwriters and selling group members
participating in this offering, or by their affiliates. In those
cases, prospective investors may view offering terms online and,
depending upon the underwriter or the selling group member,
prospective investors may be allowed to place orders online. The
underwriters may agree with VOC Sponsor to allocate a specific
number of trust units for sale to online brokerage account
holders. Any such allocation for online distributions will be
made by the underwriters on the same basis as other allocations.
Other than the prospectus in electronic format, the information
on any underwriters or any selling group members
website and any information contained in any other website
maintained by the underwriters or any selling group member is
not part of this prospectus or the registration statement of
which this prospectus forms a part, has not been approved or
endorsed by VOC Sponsor or any underwriters or any selling group
member in its capacity as underwriter or selling group member
and should not be relied upon by investors.
116
CONFLICTS/AFFILIATES
The underwriters and their affiliates may provide in the future
investment banking, financial advisory or other financial
services for VOC Sponsor and its affiliates, for which they may
receive advisory or transaction fees, as applicable, plus
out-of-pocket
expenses, of the nature and in amounts customary in the industry
for these financial services.
FINRA
RULES
Because FINRA is expected to view the trust units offered hereby
as interests in a direct participation program, this offering is
being made in compliance with Rule 2310 of the FINRA
Conduct Rules. Investor suitability with respect to the trust
units should be judged similarly to the suitability with respect
to other securities that are listed for trading on a national
securities exchange.
117
LEGAL
MATTERS
Morris James LLP, as special Delaware counsel to the trust, will
give a legal opinion as to the validity of the trust units.
Vinson & Elkins L.L.P., Houston, Texas, will give
opinions as to certain other matters relating to the offering,
including the tax opinion described in the section of this
prospectus captioned Federal income tax
consequences. Certain legal matters in connection with the
trust units offered hereby will be passed upon for the
underwriters by Baker Botts L.L.P., Houston, Texas.
EXPERTS
Certain information appearing in this registration statement
regarding the December 31, 2009 estimated quantities of
reserves of the VOC Brazos and KEP and Net Profits Interest
owned by the trust, the future net revenues from those reserves
and their present value is based on estimates of the reserves
and present values prepared by or derived from estimates
prepared by Cawley, Gillespie & Associates, Inc.,
independent petroleum engineers.
The audited financial statements included in this prospectus and
elsewhere in the registration statement have been so included in
reliance upon the reports of Grant Thornton LLP, independent
registered public accountants, upon the authority of said firm
as experts in accounting and auditing in giving said reports.
WHERE YOU
CAN FIND MORE INFORMATION
The trust and VOC Sponsor have filed with the SEC in
Washington, D.C. a registration statement, including all
amendments, under the Securities Act relating to the trust
units. As permitted by the rules and regulations of the SEC,
this prospectus does not contain all of the information
contained in the registration statement and the exhibits and
schedules to the registration statement. You may read and copy
the registration statement at the SECs public reference
room at 100 F Street, N.E., Washington, D.C.
20549. You may request copies of these documents, upon payment
of a duplicating fee, by writing to the SEC at the address in
the previous sentence. To obtain information on the operation of
the public reference rooms you may call the SEC at
(800) SEC-0330. You can also read the trust and VOC
Sponsors SEC filings, including the registration
statement, at the SECs website at www.sec.gov.
118
GLOSSARY
OF CERTAIN OIL AND NATURAL GAS TERMS
In this prospectus the following terms have the meanings
specified below.
Bbl One stock tank barrel, of 42
U.S. gallons liquid volume, used herein in reference to
crude oil and other liquid hydrocarbons.
Boe One stock tank barrel of oil equivalent,
computed on an approximate energy equivalent basis that one Bbl
of crude oil equals six Mcf of natural gas.
Boe/d One Boe per day.
Btu A British Thermal Unit, a common unit of
energy measurement.
Completion The installation of permanent
equipment for the production of oil or natural gas, or in the
case of a dry hole, the reporting of abandonment to the
appropriate agency.
Developed Acreage The number of acres that
are allocated or assignable to productive wells or wells capable
of production.
Development Well A well drilled into a proved
oil or natural gas reservoir to the depth of a stratigraphic
horizon known to be productive.
Differential The difference between a
benchmark price of oil and natural gas, such as the NYMEX crude
oil spot, and the wellhead price received.
Estimated future net revenues Also referred
to as estimated future net cash flows. The result of
applying current prices of oil and natural gas to estimated
future production from oil and natural gas proved reserves,
reduced by estimated future expenditures, based on current costs
to be incurred, in developing and producing the proved reserves,
excluding overhead.
Farm-in or farm-out agreement An agreement
under which the owner of a working interest in an oil or natural
gas lease is typically assigns the working interest or a portion
of the working interest to another party who desires to drill on
the leased acreage. Generally, the assignee is required to drill
one or more wells in order to earn its interest in the acreage.
The assignor usually retains a royalty or reversionary interest
in the lease. The interest received by an assignee is a
farm-in while the interest transferred by the
assignor is a farm-out.
Field An area consisting of either a single
reservoir or multiple reservoirs, all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition.
Gross acres or gross wells The total
acres or wells, as the case may be, in which a working interest
is owned.
Horizontal well A well that starts off being
drilled vertically but which is eventually curved to become
horizontal (or near horizontal) in order to parallel a
particular geologic formation.
MBbl One thousand barrels of crude oil or
condensate.
MBoe One thousand barrels of oil equivalent.
Mcf One thousand cubic feet of natural gas.
119
MMBbls One million barrels of crude oil or
other liquid hydrocarbons.
MMBoe One million barrels of oil equivalent.
MMcf One million cubic feet of natural gas.
Net acres or net wells The sum of the
fractional working interests owned in gross acres or wells, as
the case may be.
Net profits interest A nonoperating interest
that creates a share in gross production from an operating or
working interest in oil and natural gas properties. The share is
measured by net profits from the sale of production after
deducting costs associated with that production.
Net revenue interest An interest in all oil
and natural gas produced and saved from, or attributable to, a
particular property, net of all royalties, overriding royalties,
Net Profits Interests, carried interests, reversionary interests
and any other burdens to which the persons interest is
subject.
Plugging and abandonment Activities to remove
production equipment and seal off a well at the end of a
wells economic life.
Proved developed non-producing reserves
Proved developed reserves expected to be recovered from zones
behind casing in existing wells.
Proved developed producing reserves Proved
developed reserves that are expected to be recovered from
completion intervals currently open in existing wells and
capable of production to market.
Proved developed reserves Reserves that can
be expected to be recovered through existing wells with existing
equipment and operating methods.
Proved reserves Under SEC rules for fiscal
years ending on or after December 31, 2009, proved reserves
are defined as:
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. 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 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 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
120
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
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.
Under SEC rules for fiscal years ending prior to
December 31, 2009, proved reserves are defined as:
The estimated quantities of crude oil and natural gas, which
geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions,
i.e., prices and costs as of the date the estimate is made.
Prices include consideration of changes in existing prices
provided only by contractual arrangements, but not on
escalations based upon future conditions. Reservoirs are
considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area
of a reservoir considered proved includes (A) that portion
delineated by drilling and defined by gas-oil
and/or
oil-water contacts, if any, and (B) the immediately
adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available
geological and engineering data. In the absence of information
on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are
included in the proved classification when successful testing by
a pilot project, or the operation of an installed program in the
reservoir, provides support for the engineering analysis on
which the project or program was based. Estimates of proved
reserves do not include the following: (A) Oil that may
become available from known reservoirs but is classified
separately as indicated additional reserves; (B) crude oil
and natural gas, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors; (C) crude oil and
natural gas, that may occur in undrilled prospects; and
(D) crude oil and natural gas, that may be recovered from
oil shales, coal, gilsonite and other such sources.
Proved undeveloped reserves Proved 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.
PV-10
The present value of estimated future net revenues using a
discount rate of 10% per annum.
Recompletion The completion for production of
an existing well bore in another formation from which that well
has been previously completed.
121
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 reservoirs.
Working interest The right granted to the
lessee of a property to explore for and to produce and own oil,
gas, or other minerals. The working interest owners bear the
exploration, development, and operating costs on either a cash,
penalty, or carried basis.
Workover Operations on a producing well to
restore or increase production.
122
INDEX TO
FINANCIAL STATEMENTS
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PREDECESSOR UNDERLYING PROPERTIES:
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F-2
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F-3
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F-4
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ACQUIRED UNDERLYING PROPERTIES:
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F-10
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F-11
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F-12
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F-18
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F-19
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VOC ENERGY TRUST:
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F-20
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F-21
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F-22
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F-24
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F-25
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F-26
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F-27
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The audited combined financial statements of Predecessor can be
found beginning on page VOC F-1.
F-1
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of VOC Brazos Energy Partners, L.P.:
We have audited the accompanying combined statements of
historical revenues and direct operating expenses of the
Predecessor Underlying Properties, consisting of the Underlying
Properties of VOC Brazos Energy Partners, L.P. (VOC
Brazos) and the Underlying Properties of VOC Kansas Energy
Partners, L.L.C. under common control with VOC Brazos, for each
of the three years in the period ended December 31, 2009.
These statements are the responsibility of the management of VOC
Brazos. Our responsibility is to express an opinion on these
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. Predecessor Underlying Properties
is not required to have, nor were we engaged to perform, an
audit of Predecessor Underlying Properties internal
control over financial reporting. Our audit included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of Predecessor Underlying Properties
internal control over financial reporting. Accordingly, we
express no such opinion. An audit also 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 presentation of the statements. We
believe that our audits provide a reasonable basis for our
opinion.
The accompanying combined statements were prepared for the
purpose of complying with the rules and regulations of the
Securities and Exchange Commission as described in Note B
to the statements and are not intended to be a complete
presentation of VOC Brazos interests in the Predecessor
Underlying Properties.
In our opinion, the combined statements referred to above
present fairly, in all material respects, the historical
revenues and direct operating expenses, described in
Note B, of the Predecessor Underlying Properties for each
of the three years in the period ended December 31, 2009,
in conformity with accounting principles generally accepted in
the United States of America.
Grant Thornton LLP
Wichita, Kansas
December 29, 2010
F-2
Predecessor
Underlying Properties
AND
DIRECT OPERATING EXPENSES
|
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|
Year Ended December 31,
|
|
|
Nine Months Ended September 30,
|
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|
2007
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|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
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|
(Unaudited)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
26,040,079
|
|
|
$
|
36,632,381
|
|
|
$
|
22,757,639
|
|
|
$
|
15,019,562
|
|
|
$
|
27,383,690
|
|
Natural gas sales
|
|
|
2,494,599
|
|
|
|
3,349,695
|
|
|
|
1,510,884
|
|
|
|
1,044,777
|
|
|
|
1,856,506
|
|
Hedge and other derivative activity
|
|
|
(7,244,552
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)
|
|
|
(7,784,517
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)
|
|
|
1,477,248
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|
|
|
1,880,305
|
|
|
|
(150,626
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)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total
|
|
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21,290,126
|
|
|
|
32,197,559
|
|
|
|
25,745,771
|
|
|
|
17,944,644
|
|
|
|
29,089,570
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|
|
|
|
|
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|
|
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|
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|
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Bad debt expense (recovery)
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1,726,655
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|
(719,061
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)
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|
|
(719,061
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)
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|
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|
|
Direct operating expenses:
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|
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|
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Lease operating expenses
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6,586,226
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|
|
|
7,667,332
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|
|
|
6,787,857
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|
|
|
5,053,546
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|
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|
5,228,613
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|
Production and property taxes
|
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|
1,874,237
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|
|
|
2,531,660
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|
|
|
1,646,052
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|
|
|
1,257,919
|
|
|
|
1,918,959
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|
|
|
|
|
|
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|
|
|
|
|
|
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Total
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8,460,463
|
|
|
|
10,198,992
|
|
|
|
8,433,909
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|
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|
6,311,465
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|
|
7,147,572
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|
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|
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|
|
|
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|
Excess of revenues over direct operating expenses
|
|
$
|
12,829,663
|
|
|
$
|
20,271,912
|
|
|
$
|
18,030,923
|
|
|
$
|
12,352,240
|
|
|
$
|
21,941,998
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
The accompanying notes are an
integral part of these combined statements.
F-3
Predecessor
Underlying Properties
AND
DIRECT OPERATING EXPENSES
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
NOTE A
PROPERTIES
The Predecessor Underlying Properties consist of working
interests in substantially all of the oil and natural gas
properties located in Kansas and Texas owned by VOC Brazos
Energy Partners, L.P. (VOC Brazos) and working
interests in substantially all of the oil and natural gas
properties owned by VOC Kansas Energy Partners, LLC
(KEP) under common control with VOC Brazos Energy
Partners, L.P. (the Common Control Properties). In
connection with the closing of the initial public offering of
trust units of VOC Energy Trust, pursuant to that certain
Contribution and Exchange Agreement dated August 30, 2010, VOC
Brazos will acquire all of the membership interests in KEP in
exchange for newly issued limited partner interests in VOC
Brazos, resulting in KEP becoming a wholly-owned subsidiary of
VOC Brazos. As the Common Control Properties are deemed to be
under common control with VOC Brazos, accounting rules specify
VOC Brazos and the Common Control Properties be combined from
the earliest date they came under common control. The financial
data and operations of such assets are referred to herein as
Predecessor.
NOTE B
BASIS OF PRESENTATION
The accompanying Combined Statements of Historical Revenues and
Direct Operating Expenses were derived from the historical
accounting records of Predecessor and reflect the historical
revenues and direct operating expenses directly attributable to
the Predecessor Underlying Properties for the periods described
herein. Such amounts may not be representative of future
operations. The statements do not include depreciation,
depletion and amortization, general and administrative expenses,
interest expense or other expenses of an indirect nature. The
amounts represent Predecessors net interest in the wells
related to the Predecessor Underlying Properties.
Historical financial statements representing financial position,
results of operations and cash flows required by generally
accepted accounting principles are not presented as such
information is not readily available on an individual property
basis and not meaningful to the underlying properties.
Accordingly, the statements of historical revenues and direct
operating expenses are presented in lieu of full financial
statements prepared under
Regulation S-X.
The accompanying Combined Statements of Historical Revenues and
Direct Operating Expenses included herein were prepared on an
accrual basis. Revenue from oil and natural gas is recognized
when sold. Direct operating expenses include lease operating
expenses and production and property taxes.
These combined statements of historical revenues and direct
operating expenses do not reflect the impact of any
administrative overhead costs. VOC Brazos incurred
administrative overhead costs of $120,518, $269,139, $463,295,
$242,965 and $111,576 for the years ended December 31,
2007, 2008 and 2009 and for the nine months ended
September 30, 2009 and 2010 (unaudited), respectively. KEP
is an amalgamation of properties held by 24 owners. Prior
to their consolidation in November 2009, each owner conducted
its own accounting for its respective properties, and in most
cases the owners did not allocate overhead to the properties.
One of the reasons the owners decided to consolidate holdings
into KEP was the efficiency in sharing these
F-4
Predecessor
Underlying Properties
NOTES TO
COMBINED STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
overhead expenses. In the future, Vess Oil Corporation will
provide these overhead services to KEP. Furthermore, trust
administrative expenses are anticipated to aggregate
approximately $900,000 for 2011. Administrative expenses for
subsequent years could be greater or less depending on future
events that cannot be predicted. Included in the $900,000 annual
estimate is an annual administrative fee of $150,000 for the
trustee and an annual administrative fee of $2,500 for the
Delaware trustee as well as an annual administrative fee payable
to VOC Sponsor, which fee will total $75,000 in 2011 and will
increase by 4% each year beginning in January 2012. See
The trust. The trust will pay, out of the first cash
payment received by the trust, the trustees and Delaware
trustees legal expenses incurred in forming the trust as
well as the Delaware trustees acceptance fee in the amount
of $4,000. These costs will be deducted by the trust before
distributions are made to trust unitholders beginning in January
2012. Furthermore, the trust will incur incremental general and
administrative expenses associated with being a publicly traded
entity. As a result, historical overhead costs are not
indicative of the future overhead costs that will be borne by
VOC Energy Trust, which are expected to be approximately
$900,000 in 2011.
VOC Brazos has entered into certain swap agreements to mitigate
the effects of fluctuations in the prices of crude oil. These
agreements involve the exchange of amounts based on a
fluctuating oil price for amounts based on a fixed oil price
over the life of the agreement, without an exchange of the
notional amount upon which the payments are based. VOC Brazos
accounts for substantially all of the swap agreements as cash
flow hedges. The effective portion of the unrealized gain or
loss on the swap agreement is recorded as a component of the
accumulated other comprehensive income (loss) and reclassified
into earnings as the underlying hedged item affects earnings.
The unrealized gain or loss on the derivative instrument as well
as the swap agreements not qualifying as cash flow hedges are
reflected as hedge and other derivative activity in the
accompanying Combined Statements of Historical Revenues and
Direct Operating Expenses.
The process of preparing financial statements in conformity with
generally accepted accounting principles requires the use of
estimates and assumptions regarding certain types of revenues
and expenses. Such estimates primarily relate to unsettled
transactions and events as of the date of the financial
statements. Accordingly, upon settlement, actual results may
differ from estimated amounts.
The accompanying Combined Statements of Historical Revenues and
Direct Operating Expenses for the nine months ended
September 30, 2009 and 2010 are unaudited. In the opinion
of management of VOC Brazos, such information contains all
adjustments, consisting only of normal recurring accruals,
considered necessary for a fair presentation on the basis
described above.
NOTE C
DISCLOSURES ABOUT OIL AND GAS ACTIVITIES (UNAUDITED)
In December 2009, Predecessor adopted revised oil and gas
reserve estimation and disclosure requirements. The primary
impact of the new disclosures is to conform the definition of
proved reserves to the SEC Modernization of Oil and Gas
Reporting rules, which were issued by the SEC
F-5
Predecessor
Underlying Properties
NOTES TO
COMBINED STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
at the end of 2008. The new rules revised the definition of
proved oil and gas reserves to require that the average,
first-day-of-the-month
price during the
12-month
period before the end of the year, rather than the year-end
price, be used when estimating whether reserve quantities are
economical to produce. This same
12-month
average price is also used in calculating the aggregate amount
of (and changes in) future cash inflows related to the
standardized measure of discounted future net cash flows. The
rules also allow for the use of reliable technology to estimate
proved oil and gas reserves if those technologies have been
demonstrated to result in reliable conclusions about reserve
volumes. The unaudited supplemental information on oil and gas
exploration and production activities for 2009 has been
presented in accordance with the new reserve estimation and
disclosure rules, which may not be applied retrospectively. The
2006, 2007 and 2008 data are presented in accordance with SEC
oil and gas disclosure requirements effective during those
periods.
Estimates of the proved oil and gas reserves attributable to the
Predecessor Underlying Properties as of December 31, 2006,
2007, 2008 and 2009 are based on reports of Cawley,
Gillespie & Associates, Inc., independent petroleum
and geological engineers, and the contract property management
engineering staff of Predecessor who operate the underlying
properties, in accordance with the provisions of accounting
literature for Oil and Gas Extractive Activities. Such estimates
give effect to the combination of (i) the estimates of proved
oil and gas reserves attributable to VOC Brazos, based on
the report of Cawley, Gillespie & Associates, Inc., and
(ii) the estimates of proved oil and gas reserves attributable
to the Common Control Properties, calculated by adjusting the
estimated reserves attributable to specified working interest
percentages held by KEP outlined in the Cawley,
Gillespie & Associates, Inc. reserve report to reflect
the working interest percentages held in the Common Control
Properties. Users of this information should be aware that the
process of estimating quantities of proved and
proved developed and proved undeveloped
crude 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 additional development activity, evolving production
history and continual reassessment of the viability of
production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time
to time.
The reserve data below represent estimates only and should not
be construed as being exact.
Moreover, the discounted values should not be construed as
representative of the current market value of the oil and gas
properties. A market value determination would include many
additional factors including: (i) anticipated future oil
and gas prices; (ii) the effect of federal income taxes, if
any, on Predecessor Underlying Properties; (iii) an
allowance for return on investment; (iv) the effect of
governmental legislation; (v) the value of additional
potential reserves, not considered proved at present, which may
be recovered as a result of further exploration and development
activities; and (vi) other business risks. The following
tables set forth (i) the estimated net quantities of
proved, proved developed and proved undeveloped oil and natural
gas reserves attributable to the oil and natural gas properties,
and (ii) the standardized measure of the discounted future
net profits interest income attributable to the oil
F-6
Predecessor
Underlying Properties
NOTES TO
COMBINED STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
and gas properties and the nature of changes in such
standardized measure between years. These tables are prepared on
the accrual basis, which is the basis on which Predecessor
maintains its production records.
ESTIMATED
QUANTITIES OF OIL AND GAS RESERVES
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Oil
|
|
|
Gas
|
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
|
8,174,154
|
|
|
|
4,573,914
|
|
Revisions, extensions, discoveries and additions
|
|
|
(332,769
|
)
|
|
|
190,995
|
|
Production
|
|
|
(386,879
|
)
|
|
|
(390,593
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
7,454,506
|
|
|
|
4,374,316
|
|
Revisions, extensions, discoveries and additions
|
|
|
(569,089
|
)
|
|
|
276,043
|
|
Production
|
|
|
(389,268
|
)
|
|
|
(426,326
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
6,496,149
|
|
|
|
4,224,033
|
|
Revisions, extensions, discoveries and additions
|
|
|
2,003,848
|
|
|
|
693,788
|
|
Production
|
|
|
(407,415
|
)
|
|
|
(414,730
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
8,092,582
|
|
|
|
4,503,091
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
7,497,626
|
|
|
|
4,243,531
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
6,877,406
|
|
|
|
4,116,158
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
5,770,190
|
|
|
|
3,928,995
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
6,729,632
|
|
|
|
3,854,008
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
676,528
|
|
|
|
330,383
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
577,100
|
|
|
|
258,158
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
725,959
|
|
|
|
295,038
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
1,362,950
|
|
|
|
649,083
|
|
|
|
|
|
|
|
|
|
|
STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
FROM PROVED OIL AND GAS RESERVES
Future oil and natural gas sales and production and development
costs have been estimated in accordance with the SEC
Modernization of Oil and Gas Reporting Rules.
F-7
Predecessor
Underlying Properties
NOTES TO
COMBINED STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
The standardized measure of discounted future net cash flows
(the Standardized Measure) represents the present
value of estimated future cash inflows from proved oil and
natural gas reserves, less future development, production and
plugging and abandonment costs, discounted at 10% per annum, or
PV-10 value, to reflect timing of future cash flows. Production
costs do not include depreciation, depletion and amortization of
capitalized acquisition, exploration and development costs.
Because Predecessor bears no federal income tax expense and
taxable income is passed through to the partners of Predecessor,
no provision for federal or state income taxes is included in
the reserve report or in the calculation of the Standardized
Measure.
Estimated proved reserves and related future net revenues and
Standardized Measure were determined using index prices for oil
and natural gas, without giving effect to derivative
transactions, and were held constant throughout the life of the
properties. The index prices were $96.01 per barrel for oil and
$7.47 per MMBtu for natural gas at December 31, 2007,
$44.60 per barrel for oil and $5.62 per MMBtu for natural gas at
December 31, 2008, and the unweighted arithmetic average
first-day of-the-month prices for the prior 12 months were
$61.18 per barrel for oil and $3.83 per MMBtu for natural gas at
December 31, 2009. For purposes of comparing natural gas
prices per MMBtu and per Mcf, adjustments have been made to
reflect Btu content, shrink and compression and handling charges
as realized on an individual lease basis. The relevant average
realized prices, adjusting in the case of crude oil for
forecasted gravity, quality, transportation and marketing as
well as other factors affecting the price received at the
wellhead, were $90.83 per barrel for oil and $7.47 per Mcf for
natural gas at December 31, 2007, $39.49 per barrel for oil
and $5.61 per Mcf for natural gas at December 31, 2008 and
$55.82 per barrel for oil and $4.58 per Mcf for natural gas at
December 31, 2009. The impact of the adoption of the
authoritative guidance of the Financial Accounting Standard
Board (the FASB) on the SEC oil and gas reserve
estimation final rule on our financial statements is not
practicable to estimate due to the operation and technical
challenges associated with calculating a cumulative effect of
adoption by preparing reserve reports under both the old and new
rules.
Changes in the demand for oil and natural gas, inflation, and
other factors made such estimates inherently imprecise and
subject to substantial revision. This table should not be
construed to be an estimate of current market value of the
proved reserves attributable to Predecessors reserves.
F-8
Predecessor
Underlying Properties
NOTES TO
COMBINED STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
The estimated Standardized Measure relating to
Predecessors proved reserves at December 31, 2007,
2008 and 2009 is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Future cash inflows
|
|
$
|
709,982,661
|
|
|
$
|
285,599,020
|
|
|
$
|
479,804,227
|
|
Future costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(230,390,861
|
)
|
|
|
(152,898,120
|
)
|
|
|
(192,121,342
|
)
|
Development
|
|
|
(8,755,334
|
)
|
|
|
(12,501,184
|
)
|
|
|
(25,183,887
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
470,836,466
|
|
|
|
120,199,716
|
|
|
|
262,498,998
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less 10% discount factor
|
|
|
(264,326,635
|
)
|
|
|
(60,259,262
|
)
|
|
|
(142,117,093
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
206,509,831
|
|
|
$
|
59,940,454
|
|
|
$
|
120,381,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table sets forth the changes in the Standardized
Measure applicable to Predecessors proved oil and natural
gas reserves for the years ended December 31, 2007, 2008
and 2009:
CHANGES
IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED OIL AND GAS RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
Standardized measure at beginning of year
|
|
$
|
151,282,536
|
|
|
$
|
206,509,831
|
|
|
$
|
59,940,454
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(20,049,955
|
)
|
|
|
(29,744,163
|
)
|
|
|
(15,788,110
|
)
|
Net changes in price and production costs
|
|
|
68,207,350
|
|
|
|
(154,948,134
|
)
|
|
|
41,400,518
|
|
Changes in estimated future development costs
|
|
|
222,643
|
|
|
|
(2,726,749
|
)
|
|
|
(14,381,027
|
)
|
Development costs incurred during the period which reduce future
development costs
|
|
|
1,200,100
|
|
|
|
52,800
|
|
|
|
2,700,100
|
|
Revisions of quantity estimates
|
|
|
(8,530,591
|
)
|
|
|
(5,476,929
|
)
|
|
|
32,773,504
|
|
Accretion of discount
|
|
|
15,128,254
|
|
|
|
20,650,983
|
|
|
|
5,994,045
|
|
Change in production rates, timing and other
|
|
|
(950,506
|
)
|
|
|
25,622,815
|
|
|
|
7,742,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure at end of year
|
|
$
|
206,509,831
|
|
|
$
|
59,940,454
|
|
|
$
|
120,381,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-9
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Members of VOC Kansas Energy Partners, LLC:
We have audited the accompanying statements of historical
revenues and direct operating expenses of the Acquired
Underlying Properties, consisting of the Underlying Properties
of VOC Kansas Energy Partners, LLC (KEP) not under
common control with VOC Brazos Energy Partners, L.P., for each
of the three years in the period ended December 31, 2009.
These statements are the responsibility of management of KEP.
Our responsibility is to express an opinion on these 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. Acquired Underlying Properties is
not required to have, nor were we engaged to perform, an audit
of Acquired Underlying Properties internal control over
financial reporting. Our audit included consideration of
internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of Acquired Underlying Properties
internal control over financial reporting. Accordingly, we
express no such opinion. An audit also 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 presentation of the statements. We
believe that our audit provides a reasonable basis for our
opinion.
The accompanying statements were prepared for the purpose of
complying with the rules and regulations of the Securities and
Exchange Commission as described in Note B to the
statements and are not intended to be a complete presentation of
KEPs interests in the Acquired Underlying Properties.
In our opinion, the statements referred to above present fairly,
in all material respects, the historical revenues and direct
operating expenses, described in Note B, of the Acquired
Underlying Properties for each of the three years in the period
ended December 31, 2009, in conformity with accounting
principles generally accepted in the United States of America.
Grant Thornton LLP
Wichita, Kansas
December 29, 2010
F-10
Acquired
Underlying Properties
AND
DIRECT OPERATING EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Nine Months Ended September 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
21,327,649
|
|
|
$
|
29,297,334
|
|
|
$
|
17,602,148
|
|
|
$
|
12,158,085
|
|
|
$
|
17,298,458
|
|
Natural gas sales
|
|
|
1,904,416
|
|
|
|
2,248,210
|
|
|
|
780,880
|
|
|
|
581,580
|
|
|
|
682,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
23,232,065
|
|
|
|
31,545,544
|
|
|
|
18,383,028
|
|
|
|
12,739,665
|
|
|
|
17,981,277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bad debt expense
|
|
|
|
|
|
|
2,165,663
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
5,412,591
|
|
|
|
6,046,131
|
|
|
|
5,969,209
|
|
|
|
4,396,507
|
|
|
|
4,690,168
|
|
Production and property taxes
|
|
|
1,231,321
|
|
|
|
1,613,900
|
|
|
|
1,169,798
|
|
|
|
813,809
|
|
|
|
950,133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
6,643,912
|
|
|
|
7,660,031
|
|
|
|
7,139,007
|
|
|
|
5,210,316
|
|
|
|
5,640,301
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
16,588,153
|
|
|
$
|
21,719,850
|
|
|
$
|
11,244,021
|
|
|
$
|
7,529,349
|
|
|
$
|
12,340,976
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these statements.
F-11
Acquired
Underlying Properties
AND
DIRECT OPERATING EXPENSES
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
NOTE A
PROPERTIES
The Acquired Underlying Properties consist of working interests
in substantially all oil and natural gas properties located in
Kansas owned by VOC Kansas Energy Partners, LLC
(KEP) which are not under common control with VOC
Brazos Energy Partners, L.P (VOC Brazos). In
connection with the closing of the initial public offering of
trust units of VOC Energy Trust, pursuant to that certain
Contribution and Exchange Agreement dated August 30, 2010,
VOC Brazos will acquire all of the membership interests in KEP
in exchange for newly-issued limited partner interests in VOC
Brazos.
NOTE B
BASIS OF PRESENTATION
The accompanying Statements of Historical Revenues and Direct
Operating Expenses were derived from the historical accounting
records of KEP and reflect the historical revenues and direct
operating expenses directly attributable to the Acquired
Underlying Properties for the periods described herein. Such
amounts may not be representative of future operations. The
statements do not include depreciation, depletion and
amortization, general and administrative expenses, interest
expense or other expenses of an indirect nature. The amounts
represent KEPs net interest in the wells relating to the
Acquired Underlying Properties.
Historical financial statements representing financial position,
results of operations and cash flows required by generally
accepted accounting principles are not presented as such
information is not readily available on an individual property
basis and not meaningful to the underlying properties.
Accordingly, the statements of historical revenues and direct
operating expenses are presented in lieu of financial statements
prepared under
Rule 3-05
of
Regulation S-X.
The accompanying Statements of Historical Revenues and Direct
Operating Expenses included herein were prepared on an accrual
basis. Revenue from oil and natural gas sales is recognized when
sold.
These Statements of Historical Revenues and Direct Operating
Expenses do not reflect the impact of any administrative
overhead costs. KEP is an amalgamation of properties held by
24 owners. Prior to their consolidation in November 2009,
each owner conducted its own accounting for its respective
properties, and in most cases the owners did not allocate
overhead to the properties. One of the reasons the owners
decided to consolidate holdings into KEP was the efficiency in
sharing these overhead expenses. In the future, Vess Oil
Corporation will provide these overhead services to KEP.
Furthermore, trust administrative expenses are anticipated to
aggregate approximately $900,000 for 2011. Administrative
expenses for subsequent years could be greater or less depending
on future events that cannot be predicted. Included in the
$900,000 annual estimate is an annual administrative fee of
$150,000 for the trustee and an annual administrative fee of
$2,500 for the Delaware trustee as well as an annual
administrative fee payable to VOC Sponsor, which fee will total
$75,000 in 2011 and will increase by 4% each year beginning in
January 2012. See The trust. The trust will pay, out
of the first cash payment received by the trust, the
trustees and Delaware trustees legal expenses
incurred in forming the trust as well as the Delaware
trustees acceptance fee in the amount of
F-12
Acquired
Underlying Properties
NOTES TO
STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
$4,000. These costs will be deducted by the trust before
distributions are made to trust unitholders.
The process of preparing financial statements in conformity with
generally accepted accounting principles requires the use of
estimates and assumptions regarding certain types of revenues
and expenses. Such estimates primarily relate to unsettled
transactions and events as of the date of the financial
statements. Accordingly, upon settlement, actual results may
differ from estimated amounts.
The accompanying Statements of Historical Revenues and Direct
Operating Expenses for the nine months ended September 30,
2009 and 2010 are unaudited. In the opinion of management of
KEP, such information contains all adjustments, consisting only
of normal recurring accruals, considered necessary for a fair
presentation on the basis described above.
NOTE C
DISCLOSURES ABOUT OIL AND GAS ACTIVITIES (UNAUDITED)
In December 2009, KEP adopted revised oil and gas reserve
estimation and disclosure requirements. The primary impact of
the new disclosures is to conform the definition of proved
reserves to the SEC Modernization of Oil and Gas Reporting
rules, which were issued by the SEC at the end of 2008. The new
rules revised the definition of proved oil and gas reserves to
require that the average,
first-day-of-the-month
price during the
12-month
period before the end of the year, rather than the year-end
price, be used when estimating whether reserve quantities are
economical to produce. This same
12-month
average price is also used in calculating the aggregate amount
of (and changes in) future cash inflows related to the
standardized measure of discounted future net cash flows. The
rules also allow for the use of reliable technology to estimate
proved oil and gas reserves if those technologies have been
demonstrated to result in reliable conclusions about reserve
volumes. The unaudited supplemental information on oil and gas
exploration and production activities for 2009 has been
presented in accordance with the new reserve estimation and
disclosure rules, which may not be applied retrospectively. The
2006, 2007 and 2008 data are presented in accordance with SEC
oil and gas disclosure requirements effective during those
periods.
Estimates of the proved oil and gas reserves attributable to the
Acquired Underlying Properties as of December 31, 2006,
2007, 2008 and 2009 are based on the report of Cawley,
Gillespie & Associates, Inc., independent petroleum
and geological engineers, and the contract property management
engineering staff of KEP who operate the underlying properties,
in accordance with the provisions of accounting literature for
Oil and Gas Extractive Activities. Such estimates are calculated
by adjusting the estimated reserves attributable to specified
working interest percentages held by KEP outlined in the Cawley,
Gillespie & Associates, Inc. reserve report to reflect
the working interest percentages held in the Acquired Underlying
Properties. Users of this information should be aware that the
process of estimating quantities of proved and
proved developed and proved undeveloped
crude 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 additional
F-13
Acquired
Underlying Properties
NOTES TO
STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
development activity, evolving production history and continual
reassessment of the viability of production under varying
economic conditions. Consequently, material revisions to
existing reserve estimates occur from time to time.
The reserve data below represent estimates only and should not
be construed as being exact.
Moreover, the discounted values should not be construed as
representative of the current market value of the oil and gas
properties. A market value determination would include many
additional factors including: (i) anticipated future oil
and natural gas prices; (ii) the effect of federal income
taxes, if any, on the Acquired Underlying Properties;
(iii) an allowance for return on investment; (iv) the
effect of governmental legislation; (v) the value of
additional potential reserves, not considered proved at present,
which may be recovered as a result of further exploration and
development activities; and (vi) other business risks. The
following tables set forth (i) the estimated net quantities
of proved, proved developed and proved undeveloped oil, and
natural gas reserves attributable to the oil and gas properties,
and (ii) the standardized measure of the discounted future
net profits interest income attributable to the oil and gas
properties and the nature of changes in such standardized
measure between years. These tables are prepared on the accrual
basis, which is the basis on which KEP maintains its production
records.
F-14
Acquired
Underlying Properties
NOTES TO
STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
ESTIMATED
QUANTITIES OF OIL AND GAS RESERVES
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
|
4,857,130
|
|
|
|
3,352,686
|
|
Revisions, extensions, discoveries and additions
|
|
|
|
|
|
|
|
|
Production
|
|
|
(318,523
|
)
|
|
|
(347,057
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
4,538,607
|
|
|
|
3,005,629
|
|
Revisions, extensions, discoveries and additions
|
|
|
(1,041,821
|
)
|
|
|
(48,799
|
)
|
Production
|
|
|
(314,620
|
)
|
|
|
(323,964
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
3,182,166
|
|
|
|
2,632,866
|
|
Revisions, extensions, discoveries and additions
|
|
|
979,834
|
|
|
|
(395,370
|
)
|
Production
|
|
|
(324,329
|
)
|
|
|
(278,022
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
3,837,671
|
|
|
|
1,959,474
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
4,857,130
|
|
|
|
3,352,686
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
4,538,607
|
|
|
|
3,005,629
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
3,182,166
|
|
|
|
2,632,866
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
3,837,671
|
|
|
|
1,959,474
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
FROM PROVED OIL AND GAS RESERVES
Future oil and natural gas sales and production and development
costs have been estimated in accordance with the
SEC Modernization of Oil and Gas Reporting Rules.
The standardized measure of discounted future net cash flows
(the Standardized Measure) represents the present
value of estimated future cash inflows from proved oil and
natural gas reserves, less future development, production and
plugging and abandonment costs, discounted at 10% per
annum, or
PV-10 value,
to reflect timing of future cash flows. Production costs do not
include depreciation, depletion and amortization of capitalized
acquisition, exploration and development costs. Because KEP
bears no federal income tax expense and taxable income is passed
through to the members of KEP, no provision for federal or state
income taxes is included in the reserve report or in the
calculation of the Standardized Measure.
F-15
Acquired
Underlying Properties
NOTES TO
STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
Estimated proved reserves and related future net revenues and
Standardized Measure were determined using index prices for oil
and natural gas, without giving effect to derivative
transactions, and were held constant throughout the life of the
properties. The index prices were $96.01 per barrel for oil and
$7.47 per MMBtu for natural gas at December 31, 2007,
$44.60 per barrel for oil and $5.62 per MMBtu for natural gas at
December 31, 2008, and the unweighted arithmetic average
first-day of-the-month prices for the prior 12 months were
$61.18 per barrel for oil and $3.83 per MMBtu for natural gas at
December 31, 2009. The relevant average realized prices,
adjusting in the case of crude oil for forecasted gravity,
quality, transportation and marketing as well as other factors
affecting the price received at the wellhead, were $90.83 per
barrel for oil and $7.47 per Mcf for natural gas at
December 31, 2007, $39.49 per barrel for oil and $5.61 per
Mcf for natural gas at December 31, 2008 and $55.82 per
barrel for oil and $4.58 per Mcf for natural gas at
December 31, 2009. The impact of the adoption of the
authoritative guidance of the Financial Accounting Standard
Board (the FASB) on the SEC oil and gas reserve
estimation final rule on our financial statements is not
practicable to estimate due to the operation and technical
challenges associated with calculating a cumulative effect of
adoption by preparing reserve reports under both the old and new
rules.
Changes in the demand for oil and natural gas, inflation, and
other factors make such estimates inherently imprecise and
subject to substantial revision. This table should not be
construed to be an estimate of current market value of the
proved reserves attributable to Predecessors reserves.
The estimated Standardized Measure relating to
Predecessors proved reserves at December 31, 2007,
2008 and 2009 is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Future cash inflows
|
|
$
|
429,961,058
|
|
|
$
|
130,045,214
|
|
|
$
|
212,587,116
|
|
Future costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(145,593,930
|
)
|
|
|
(68,863,533
|
)
|
|
|
(103,484,949
|
)
|
Development
|
|
|
|
|
|
|
|
|
|
|
(133,055
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
284,367,128
|
|
|
|
61,181,681
|
|
|
|
108,969,112
|
|
Less 10% discount factor
|
|
|
(150,905,146
|
)
|
|
|
(26,506,431
|
)
|
|
|
(50,661,158
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
133,461,982
|
|
|
$
|
34,675,250
|
|
|
$
|
58,307,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-16
Acquired
Underlying Properties
NOTES TO
STATEMENTS OF HISTORICAL REVENUES
AND
DIRECT OPERATING EXPENSES (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
The following table sets forth the changes in the Standardized
Measure applicable to the proved oil and natural gas reserves of
the Acquired Underlying Properties for the years ended
December 31, 2007, 2008 and 2009:
CHANGES
IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED OIL AND GAS RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
Standardized measure at beginning of year
|
|
$
|
129,328,212
|
|
|
$
|
133,461,982
|
|
|
$
|
34,675,250
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(16,588,154
|
)
|
|
|
(23,885,512
|
)
|
|
|
(11,244,020
|
)
|
Net changes in price and production costs
|
|
|
7,789,103
|
|
|
|
(104,299,841
|
)
|
|
|
13,586,121
|
|
Changes in estimated future development costs
|
|
|
|
|
|
|
|
|
|
|
(123,046
|
)
|
Revisions of quantity estimates
|
|
|
|
|
|
|
(10,865,844
|
)
|
|
|
15,494,644
|
|
Accretion of discount
|
|
|
12,932,821
|
|
|
|
13,346,198
|
|
|
|
3,467,525
|
|
Change in production rates, timing and other
|
|
|
|
|
|
|
26,918,267
|
|
|
|
2,451,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure at end of year
|
|
$
|
133,461,982
|
|
|
$
|
34,675,250
|
|
|
$
|
58,307,954
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-17
UNAUDITED
PRO FORMA STATEMENTS OF HISTORICAL REVENUES AND
DIRECT OPERATING EXPENSES OF THE UNDERLYING
PROPERTIES
Introduction
The following unaudited pro forma statements of historical
revenues and direct operating expenses are of the Predecessor
Underlying Properties, as adjusted to give effect to the
acquisition of the Acquired Underlying Properties as if the
acquisition had occurred on January 1, 2009. As certain of
the Underlying Properties held by KEP (the Common Control
Properties) are deemed to be under common control with VOC
Brazos, accounting rules specify that VOC Brazos and the Common
Control Properties be combined from the earliest date they came
under common control. The financial data and operations of such
assets are referred to herein as the Predecessor
Underlying Properties and are described in more detail in
VOC Sponsor Managements discussion and
analysis of financial condition and results of operations.
The Underlying Properties of KEP not deemed to be under common
control with the assets of VOC Brazos are referred to herein as
the Acquired Underlying Properties.
The unaudited pro forma statements of historical revenues and
direct operating expenses are for informational purposes only.
They do not purport to present the results of the combined
historical revenues and direct operating expenses of the
Underlying Properties that would have actually occurred had the
acquisition of the Acquired Underlying Properties occurred on
January 1, 2009.
The unaudited pro forma statements of historical revenues and
direct operating expenses should be read in conjunction with
The Underlying Properties Discussion and
Analysis of Historical Results of the Underlying
Properties, the audited combined statements of historical
revenues and direct operating expenses of Predecessor Underlying
Properties and the audited statements of historical revenues and
direct operating expenses of the Acquired Underlying Properties
included in this prospectus.
F-18
UNAUDITED
PRO FORMA STATEMENTS OF HISTORICAL REVENUES
AND DIRECT OPERATING EXPENSES OF THE UNDERLYING
PROPERTIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
Nine Months Ended September 30, 2010
|
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Pro Forma
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Pro Forma
|
|
|
|
|
|
|
(a)
|
|
|
|
|
|
|
|
|
(a)
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$
|
22,757,639
|
|
|
$
|
17,602,148
|
|
|
$
|
40,359,787
|
|
|
$
|
27,383,690
|
|
|
$
|
17,298,458
|
|
|
$
|
44,682,148
|
|
Natural gas sales
|
|
|
1,510,884
|
|
|
|
780,880
|
|
|
|
2,291,764
|
|
|
|
1,856,506
|
|
|
|
682,819
|
|
|
|
2,539,325
|
|
Hedge activity
|
|
|
1,477,248
|
|
|
|
|
|
|
|
1,477,248
|
|
|
|
(150,626
|
)
|
|
|
|
|
|
|
(150,626
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
25,745,771
|
|
|
|
18,383,028
|
|
|
|
44,128,799
|
|
|
|
29,089,570
|
|
|
|
17,981,277
|
|
|
|
47,070,847
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bad debt recovery
|
|
|
(719,061
|
)
|
|
|
|
|
|
|
(719,061
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Direct operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
6,787,857
|
|
|
|
5,969,209
|
|
|
|
12,757,066
|
|
|
|
5,228,613
|
|
|
|
4,690,168
|
|
|
|
9,918,781
|
|
Production and property taxes
|
|
|
1,646,052
|
|
|
|
1,169,798
|
|
|
|
2,815,850
|
|
|
|
1,918,959
|
|
|
|
950,133
|
|
|
|
2,869,092
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
8,433,909
|
|
|
|
7,139,007
|
|
|
|
15,572,916
|
|
|
|
7,147,572
|
|
|
|
5,640,301
|
|
|
|
12,787,873
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses
|
|
$
|
18,030,923
|
|
|
$
|
11,244,021
|
|
|
$
|
29,274,944
|
|
|
$
|
21,941,998
|
|
|
$
|
12,340,976
|
|
|
$
|
34,282,974
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Pro forma adjustment to give effect
to the acquisition of the Acquired Properties as if the
acquisition had occurred on January 1, 2009.
|
F-19
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Unitholders of VOC Energy Trust:
We have audited the accompanying statement of assets and trust
corpus of VOC Energy Trust (the Trust) as of
December 17, 2010. This financial statement is the
responsibility of the management of VOC Brazos Energy Partners,
L.P. 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 statement of assets and
trust corpus is free of material misstatement. The Trust is not
required to have, nor were we engaged to perform, an audit of
its internal control over financial reporting. Our audit
included consideration of internal control over financial
reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of
expressing an opinion on the effectiveness of the Trusts
internal control over financial reporting. Accordingly, we
express no such opinion. An audit also includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the statement of assets and trust corpus, assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall statement of
assets and trust corpus presentation. We believe that our audit
provides a reasonable basis for our opinion.
As described in Note B to the statement of assets and trust
corpus, this statement has been prepared on a cash basis of
accounting, which is a comprehensive basis of accounting other
than accounting principles generally accepted in the United
States of America.
In our opinion, the statement of assets and trust corpus
referred to above presents fairly, in all material respects, the
financial position of the Trust as of December 17, 2010, on
the basis of accounting described in Note B.
Grant Thornton LLP
Wichita, Kansas
December 29, 2010
F-20
VOC
ENERGY TRUST
|
|
|
|
|
|
|
December 17,
|
|
|
2010
|
|
ASSETS
|
|
|
|
|
Cash
|
|
$
|
1,000
|
|
|
|
|
|
|
TRUST CORPUS
|
|
|
|
|
Trust Corpus
|
|
$
|
1,000
|
|
|
|
|
|
|
The accompanying notes are an
integral part of this financial statement.
F-21
VOC
Energy Trust
NOTE A
ORGANIZATION OF THE TRUST
VOC Energy Trust (the Trust) is a statutory trust
formed on November 3, 2010 (capitalized on
December 17, 2010), under the Delaware Statutory
Trust Act pursuant to a Trust Agreement (the
Trust Agreement) among VOC Brazos Energy
Partners, L.P. (VOC Brazos), as trustor, The Bank of
New York Mellon Trust Company, N.A., as Trustee (the
Trustee), and Wilmington Trust Company, as
Delaware Trustee (the Delaware Trustee).
The Trust was created to acquire and hold a term net profits
interest (the Net Profits Interest) for the benefit
of the Trust unitholders. In connection with the closing of the
initial public offering of trust units of the Trust, VOC Brazos
will convey the Net Profits Interest to the Trust. The Net
Profits Interest is an interest during the term of the trust in
underlying properties consisting of working interests in
substantially all of its oil and natural gas properties in the
states of Kansas and Texas held by VOC Brazos and VOC Kansas
Energy Partners, L.L.C. as of the date of the conveyance of the
Net Profits Interest to the Trust (the Underlying
Properties).
The Net Profits Interest is passive in nature and the Trustee
will have no management control over and no responsibility
relating to the operation of the Underlying Properties. The Net
Profits Interest entitles the Trust to receive 80% of the net
proceeds attributable to the net profits interest during the
term of the Trust. The net profits interest will terminate on
the later to occur of (1) December 31, 2030 or
(2) the time when 9.7 million barrels of oil
equivalent have been produced from the Underlying Properties and
sold, and the Trust will soon thereafter wind up its affairs and
terminate.
The Trustee can authorize the Trust to borrow money to pay trust
administrative or incidental expenses that exceed cash held by
the Trust. The Trustee may authorize the Trust to borrow from
the Trustee or the Delaware Trustee as a lender provided the
terms of the loan are similar to the terms it would grant to a
similarly situated commercial customer with whom it did not have
a fiduciary relationship. The Trustee may also deposit funds
awaiting distribution in an account with itself and make other
short term investments with the funds distributed to the Trust.
NOTE B
TRUST ACCOUNTING POLICIES
A summary of the significant accounting policies of the Trust
follows.
1. Basis
of accounting
The Trust uses the cash basis of accounting to report Trust
receipts of the Net Profits Interest and payments of expenses
incurred. The Net Profits Interest represents the right to
receive revenues (oil and natural gas sales less direct
operating expenses (lease operating expenses and production and
property taxes) and development expenses of the Underlying
Properties plus any payments made or net of payments received in
connection with the settlement of certain hedge contracts, times
80%. Cash distributions of the Trust will be made based on the
amount of cash received by the Trust pursuant to terms of the
conveyance creating the Net Profits Interest.
Amortization of the investment in Net Profits Interest
calculated on a
unit-of-production
basis is charged directly to trust corpus.
F-22
VOC
Energy Trust
NOTES TO
STATEMENT OF ASSETS AND
TRUST CORPUS (Continued)
This comprehensive basis of accounting other than in generally
accepted accounting principles (GAAP) corresponds to
the accounting permitted for royalty trusts by the
U.S. Securities and Exchange Commission as specified by
Staff Accounting Bulletin Topic 12:E, Financial Statements
of Royalty Trusts.
Investment in the net profits interest is periodically assessed
to determine whether its aggregate value has been impaired below
its total capitalized cost based on the underlying properties.
The Trust will provide a write-down to its investment in the net
profits interest if and to the extent that total capitalized
costs, less accumulated depreciation, depletion and
amortization, exceed undiscounted future net revenues
attributable to the Trusts interests in the proved oil and
gas reserves of the underlying properties.
2. Use
of estimates
The preparation of the financial statements requires the Trust
to make estimates and assumptions that affect the reported
amount of assets and liabilities and the reported amounts of
revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Tax counsel to the Trust advised the Trust at the time of
formation that, under then current tax laws, the net profits
interest should be treated as a debt instrument for federal
income tax purposes, and the Trust should be required to treat a
portion of each payment it receives with respect to the net
profits interest as interest income in accordance with the
noncontingent bond method under the original issue
discount rules contained in the Internal Revenue Code of 1986,
as amended, and the corresponding regulations. The Trust will be
treated as a grantor trust for federal income tax purposes.
Trust unitholders will be considered to own and receive the
trusts assets and income and will be directly taxable
thereon as if no trust were in existence.
|
|
NOTE D
|
DISTRIBUTIONS
TO UNITHOLDERS
|
The Trustee determines for each quarter the amount available for
distribution to the Trust unitholders. This distribution is
expected to be made on or before the 45th day of the month
following the end of each quarter to the Trust unitholders of
record on the 30th day of the month following the end of
each quarter (or the next succeeding business day). Such amounts
will be equal to the excess, if any, of the cash received by the
Trust during the preceding quarter, over the liabilities of the
Trust paid during such quarter, subject to adjustments for
changes made by the Trustee during such quarter in any cash
reserves established for future liabilities of the Trust.
|
|
NOTE E
|
SUBSEQUENT
EVENTS
|
Management has reviewed activity through December 29, 2010,
which is considered the date through which these financial
statements are available to be issued for events requiring
recognition or disclosure.
F-23
VOC
Energy Trust
Introduction
In connection with the closing of the initial public offering of
trust units of VOC Energy Trust, pursuant to that certain
Contribution and Exchange Agreement dated August 30, 2010,
VOC Brazos Energy Partners, L.P. (VOC Brazos) will
acquire the membership interests in VOC Kansas Energy Partners,
LLC (KEP) in exchange for newly issued limited
partnership interests in VOC Brazos, resulting in KEP becoming a
wholly-owned subsidiary of VOC Brazos (the KEP
Acquisition). As used herein, VOC Sponsor
refers to VOC Brazos after giving effect to the KEP Acquisition.
Concurrent with the closing of the initial public offering, VOC
Sponsor will convey to the Trust the Net Profits Interest
representing the right to receive 80% of the net proceeds from
production from substantially all of the interests in oil and
natural gas properties in the states of Kansas and Texas held by
VOC Sponsor as of the date of the conveyance of the net profits
interest to the trust (the Underlying Properties).
The unaudited pro forma statement of assets and trust corpus
presents the beginning statement of assets and trust corpus of
the Trust as of September 30, 2010, as adjusted to give
effect to the conveyance of the Net Profits Interest to the
Trust and the issuance of trust units as if they occurred on
September 30, 2010. The unaudited pro forma statements of
distributable income for the year ended December 31, 2009
and the nine months ended September 30, 2010, give effect
to the conveyance of the Net Profits Interest to the Trust and
the issuance of trust units as if they occurred on
January 1, 2009, reflecting only pro forma adjustments
expected to have a continuing impact on the combined results.
These unaudited pro forma financial statements are for
informational purposes only. They do not purport to present the
results that would have actually occurred had the net profits
interest conveyance been completed on the assumed dates or for
the periods presented, or which may be realized in the future.
To produce the pro forma financial information, management of
VOC Sponsor made certain estimates. The accompanying unaudited
pro forma statement of assets and trust corpus assumes an
issuance
of
trust units at a public offering price of
$ per unit. These estimates are
based on the most recently available information. To the extent
there are significant changes in these amounts, the assumptions
and estimates herein could change significantly.
The unaudited pro forma statement of assets and trust corpus and
unaudited pro forma statements of distributable income should be
read in conjunction with the accompanying notes to such
unaudited pro forma financial information and the audited
statement of assets and trust corpus of the Trust, including the
related notes, included in this prospectus and elsewhere in the
registration statement.
F-24
VOC
ENERGY TRUST
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2010
|
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Pro Forma
|
|
|
|
(a)
|
|
|
|
|
|
|
|
|
ASSETS
|
Cash
|
|
$
|
1,000
|
|
|
$
|
|
|
|
$
|
1,000
|
|
Investment in Net Profits Interest (See Note E)
|
|
|
|
|
|
|
121,794,079
|
|
|
|
121,794,079
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,000
|
|
|
$
|
121,794,079
|
|
|
$
|
121,795,079
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TRUST CORPUS
|
|
|
|
|
|
|
|
|
|
|
|
|
trust
units issued and outstanding
|
|
$
|
1,000
|
|
|
$
|
121,794,079
|
|
|
$
|
121,795,079
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
VOC Energy Trust was formed in
November, 2010 and capitalized on December 17, 2010.
|
The accompanying notes are an
integral part of the unaudited pro forma financial statement.
F-25
VOC
ENERGY TRUST
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Nine Months Ended
|
|
|
|
December 31, 2009
|
|
|
September 30, 2010
|
|
|
Historical Results
|
|
|
|
|
|
|
|
|
Income from the net profits interest (See Note D)
|
|
$
|
19,316,462
|
|
|
$
|
20,363,174
|
|
Pro Forma Adjustments
|
|
|
|
|
|
|
|
|
Less trust general and administrative expenses (See
Note E(a))
|
|
|
900,000
|
|
|
|
675,000
|
|
|
|
|
|
|
|
|
|
|
Distributable income
|
|
$
|
18,416,462
|
|
|
$
|
19,688,174
|
|
|
|
|
|
|
|
|
|
|
Distributable income per unit
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of the unaudited pro forma financial statements.
F-26
VOC
Energy Trust
NOTE A
BASIS OF PRESENTATION
In connection with the closing of the initial public offering of
trust units of VOC Energy Trust (the Trust),
pursuant to that Certain Contribution and Exchange Agreement
dated August 30, 2010, VOC Brazos Energy Partners, L.P.
(VOC Brazos) will acquire the membership interests
in VOC Kansas Energy Partners, LLC (KEP) in exchange
for newly issued limited partnership interests in VOC Brazos,
resulting in KEP becoming a wholly-owned subsidiary of VOC
Brazos (the KEP Acquisition). As used herein,
VOC Sponsor refers to VOC Brazos after giving effect
to the KEP Acquisition. Concurrent with the closing of the
initial public offering, VOC Sponsor will convey to the Trust a
term net profits interest (the Net Profits Interest)
representing the right to receive 80% of the net proceeds from
production from substantially all of the interests in oil and
natural gas properties in the states of Kansas and Texas held by
VOC Sponsor as of the date of the conveyance of the net profits
interest to the Trust (the Underlying Properties).
The unaudited pro forma statement of assets and trust corpus
presents the beginning statement of assets and trust corpus of
the Trust as of September 30, 2010, as adjusted to give
effect to the conveyance of the Net Profits Interest to the
Trust and the issuance of trust units as if they occurred on
September 30, 2010. The unaudited pro forma statements of
distributable income for the year ended December 31, 2009
and the nine months ended September 30, 2010, give effect
to the conveyance of the Net Profits Interest to the Trust and
the issuance of trust units as if they occurred on
January 1, 2009, reflecting only pro forma adjustments
expected to have a continuing impact on the combined results.
The Trust was formed on November 3, 2010 under Delaware law
to acquire and hold the Net Profits Interest for the benefit of
the holders of the trust units. The Net Profits Interest is
passive in nature and The Bank of New York Mellon Trust Company,
N.A., as trustee (the Trustee), will have no
management control over and no responsibility relating to the
operation of the Underlying Properties.
NOTE B
TRUST ACCOUNTING POLICIES
These Unaudited Pro Forma Statements were prepared using the
accrual basis information from the historical revenue and direct
operating expenses of the underlying properties. The Trust uses
the cash basis of accounting to report Trust receipts of the
term Net Profits Interest and payments of expenses incurred.
Actual cash receipts may vary due to timing delays of actual
cash receipts from the property operators or purchasers and due
to wellhead and pipeline volume balancing agreements or
practices. The actual cash distributions of the Trust will be
made based on the terms of the conveyance creating the
Trusts Net Profits Interest which is on a cash basis of
accounting. An adjustment is made for development expenses which
will reduce the cash distributions but are not shown as expenses
on the accrual basis historical data.
Investment in the Net Profits Interest is recorded initially at
the historic cost of VOC Sponsor and periodically assessed to
determine whether its aggregate value has been impaired below
its total capitalized cost based on the underlying properties.
The Trust will provide a write-down to its investment in the net
profits interest to the extent that total capitalized costs,
less accumulated depreciation, depletion and amortization,
exceed undiscounted future net revenues attributable to the
proved oil and gas reserves of the underlying properties.
F-27
VOC Sponsor believes that the assumptions used provide a
reasonable basis for presenting the significant effects directly
attributable to this transaction.
This unaudited pro forma financial information should be read in
conjunction with the Statement of Historical Revenues and Direct
Operating Costs for Underlying Properties and related notes for
the periods presented.
NOTE C
INCOME TAXES
The Trust is a Delaware statutory trust and is not required to
pay federal or state income taxes. Accordingly, no provision for
Federal or state income taxes has been made.
NOTE D
INCOME FROM NET PROFITS INTEREST
The table below outlines the calculation of Trust income from
Net Profits Interest derived from the excess of revenues over
direct operating expenses of the Underlying Properties for the
year ended December 31, 2009 and the nine months ended
September 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Nine Months Ended
|
|
|
|
December 31, 2009
|
|
|
September 30, 2010
|
|
|
Excess of revenues over direct operating expenses of Underlying
Properties
|
|
$
|
29,274,944
|
|
|
$
|
34,282,974
|
|
Development expenses (1)
|
|
|
5,129,366
|
|
|
|
8,829,006
|
|
|
|
|
|
|
|
|
|
|
Excess of revenues over direct operating expenses and
development expenses
|
|
|
24,145,578
|
|
|
|
25,453,968
|
|
Times Net Profits Interest over the term of the Trust
|
|
|
80
|
%
|
|
|
80
|
%
|
|
|
|
|
|
|
|
|
|
Trust Income from Net Profits Interest
|
|
$
|
19,316,462
|
|
|
$
|
20,363,174
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Per terms of the net profits
interest development costs are to be deducted when calculating
the distributable income to the Trust.
|
NOTE E
PRO FORMA ADJUSTMENTS
The Net Profits Interest is recorded at the historical cost of
VOC Sponsor and is calculated as follows as of
September 30, 2010:
|
|
|
|
|
Oil and gas properties consisting of the Underlying Properties
|
|
$
|
180,181,637
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(26,331,798
|
)
|
|
|
|
|
|
Net Property Value
|
|
|
153,849,839
|
|
Plus hedge asset
|
|
|
1,245,391
|
|
Less asset retirement obligation (1)
|
|
|
(5,246,492
|
)
|
|
|
|
|
|
Net property to be conveyed
|
|
|
149,848,738
|
|
|
|
|
|
|
Times 80% Net Profits Interest to Trust with the asset
retirement obligation limited to the life of the Trust
|
|
$
|
121,794,079
|
|
|
|
|
|
|
|
|
|
(1)
|
|
See Note F below for a
description of asset retirement obligation.
|
(a) These Trust administrative expenses are anticipated to
aggregate approximately $900,000 for 2011. Administrative
expenses for subsequent years could be greater or less depending
on future events that cannot be predicted. Included in the
$900,000 annual estimate is an annual
F-28
administrative fee of $150,000 for the Trustee and an annual
administrative fee of $2,500 for the Delaware trustee as well as
an annual administrative fee payable to VOC Sponsor, which fee
will total $75,000 in 2011 and will increase by 4% each year
beginning in January 2012. See The trust. The Trust
will pay, out of the first cash payment received by the trust,
the trustees and Delaware trustees legal expenses
incurred in forming the trust as well as the Delaware
trustees acceptance fee in the amount of $4,000. These
costs will be deducted by the trust before distributions are
made to trust unitholders.
NOTE
F ASSET RETIREMENT OBLIGATIONS
Accounting guidance requires that the fair value of a liability
for an asset retirement obligation be recognized in the period
in which the liability is incurred. The liability is measured at
discounted fair value and is adjusted to its present value in
subsequent periods as accretion expense is recorded. Such
accretion expense is included in depreciation, depletion,
amortization and accretion in the accompanying statements of
earnings. The corresponding asset retirement costs are
capitalized as part of the carrying amount of the related
long-lived asset and amortized over the assets useful
life. If the fair value of the estimated retirement obligation
changes, an adjustment is recorded for both the asset retirement
obligation and the asset retirement cost. VOC Sponsors
asset retirement obligations are primarily associated with the
plugging and abandoning of oil and gas properties.
The estimated plug and abandon dates change routinely based upon
additional engineering data and changes in the price of oil
impacting the date when the well is no longer economically
feasible to operate. The asset retirement obligation is measured
on an annual basis based upon the then current plug and abandon
dates of the wells using the original measurement date rates.
Asset retirement obligations on new wells drilled are calculated
on their initial measurement date based upon the then current
interest rate environment.
F-29
BUSINESS
AND PROPERTIES OF VOC SPONSOR
In connection with the closing of the initial public offering of
trust units of VOC Energy Trust, pursuant to that certain
Contribution and Exchange Agreement dated August 30, 2010, VOC
Brazos Energy Partners, L.P. (VOC Brazos) will
acquire all of the membership interests in VOC Kansas
Energy Partners, L.L.C. (KEP) in exchange for newly
issued limited partnership interests in VOC Brazos, resulting in
KEP becoming a wholly-owned subsidiary of VOC Brazos (the
KEP Acquisition). As used herein, VOC
Sponsor refers to VOC Brazos after giving effect to the
KEP Acquisition. VOC Brazos is a privately held limited
partnership engaged in the production and development of oil and
natural gas from properties located in Texas. VOC Brazos was
formed in May 2003. KEP was formed in November 2009 to develop
and produce oil and natural gas from properties primarily
located in Kansas along with a limited number of Texas
properties. Members of KEP acquired interests in the properties
owned by KEP through various acquisitions and drilling
activities that have occurred since 1979. See Prospectus
summary Formation transactions for a more
detailed discussion of the KEP Acquisition.
The Underlying Properties consist of substantially all of the
oil and natural gas properties of VOC Sponsor. Therefore, all
information set forth in the prospectus related to the reserves
and operations of the Underlying Properties is the same as the
information that would be set forth for VOC Sponsor.
As of December 31, 2009, VOC Sponsor held interests in
approximately 892 gross (550.2 net) producing wells, and
proved reserves of the Underlying Properties were approximately
13.0 MMBoe. As of December 31, 2009, approximately 98%
of the total proved reserves attributable to the Underlying
Properties, based on pre-tax present value of estimated future
net revenue using a discount rate of ten percent per annum
(PV-10),
were operated, or operated on a contract operator basis, by Vess
Oil Corporation (which we refer to as Vess Oil), L.
D. Drilling Inc. or Davis Petroleum, Inc. (which we refer to
collectively with Vess Oil as the VOC Operators),
with Vess Oil operating approximately 90% of the total proved
reserves and L.D. Drilling Inc. and Davis Petroleum, Inc.
operating approximately 8% of the total proved reserves. Vess
Oil has operated oil and natural gas properties in Kansas for
more than 30 years and, according to statistics furnished
by the Kansas Geological Survey was the third largest operator
of oil properties in Kansas measured by production during 2009.
Vess Oil currently operates over 1,600 oil, natural gas and
service wells located primarily in Kansas, with growing
operations in Texas. As of September 30, 2010, Vess Oil
employed 19 full-time employees, three contract
professionals and 14 contract personnel in its Wichita office
and in five field and satellite offices.
The trust units do not represent interests in, or obligations
of, VOC Sponsor.
MANAGEMENT
OF VOC SPONSOR
VOC Sponsor does not currently have any executive officers,
directors or employees. Instead, VOC Sponsor is managed by its
general partner, Vess Texas Partners, LLC. The officers of Vess
Texas Partners LLC consist of employees of Vess Oil. None of the
members of the executive management team of Vess Oil who perform
management functions for VOC Sponsor receive any direct
compensation from the trust or from VOC Sponsor.
VOC-2
Set forth in the table below are the names, ages, and titles at
Vess Oil of the members of the executive management team of Vess
Oil who perform management functions on behalf of Vess Texas
Partners, LLC, VOC Sponsors general partner:
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Title
|
|
J. Michael Vess
|
|
|
59
|
|
|
President & Chief Executive Officer
|
William R. Horigan
|
|
|
61
|
|
|
Vice President of Operations
|
Brian Gaudreau
|
|
|
55
|
|
|
Vice President of Land
|
Barry Hill
|
|
|
34
|
|
|
Vice President and Chief Financial Officer
|
Alan Howarter
|
|
|
54
|
|
|
Vice President of Financial Reporting
|
Executive
Management from Vess Oil
J. Michael Vess is the President, Chief Executive
Officer and principal owner of Vess Oil. Mr. Vess
co-founded Vess Oil in 1979 and continues to be responsible for
the coordination and supervision of exploration and production
and the acquisition of its oil and natural gas reserves.
Mr. Vess received a Bachelor of Business Administration
degree from Wichita State University in 1973 and subsequently
received his CPA certificate. Mr. Vess currently serves on
the Board of Directors and Executive Committees for the Kansas
Independent Oil and Gas Association (KIOGA) and is
the current Chairman of the KIOGA Committee on Electricity. In
addition, he is Past Chairman of the KIOGA Tax Committee and a
current member of the Interstate Oil and Gas Compact Commission
Outreach Committee.
William R. Horigan is the Vice President of Operations
for Vess Oil where he is responsible for the engineering,
enhancement and exploitation of its existing properties as well
as the engineering analysis and evaluation of its future reserve
acquisitions. Mr. Horigan joined Vess Oil in 1988 as
Operations Manager. Prior to joining Vess Oil, Mr. Horigan
served in various petroleum engineering capacities for Amoco
Production Company beginning in 1975. Mr. Horigan later
served as Division Operations Manager for Slawson Oil
Company. Mr. Horigan graduated from the University of
Kansas in 1974 with a Bachelor of Science degree in Chemical
Engineering. Mr. Horigan is a member of the Society of
Petroleum Engineers and has served on the Executive Board for
the Wichita Section. He is also a member of the Producers
Advisory Board of the KU Tertiary Oil Recovery Project of the
Petroleum Technology Transfer Council of the North Mid-Continent
Region.
Brian Gaudreau is the Vice President of Land for Vess Oil
where he is responsible for land, contracts and acquisitions.
Mr. Gaudreau joined Vess Oil in 2002 as Vice President,
Land and Acquisitions. Prior to joining Vess Oil, he held the
title of Manager, Land and Acquisitions for Stelbar Oil
Corporation, Inc. beginning in 1989. Mr. Gaudreau graduated
from the University of Kansas in 1977 with a Bachelors degree in
Economics. Mr. Gaudreau belongs to the American Association
of Professional Landmen, is a Director and serves on the
Executive Committee of KIOGA, and belongs to the Dallas
Acquisitions, Divestitures, and Mergers Energy Forum.
Barry Hill is the Vice President and Chief Financial
Officer for Vess Oil responsible for planning, directing and
coordinating finance activities. Mr. Hill joined Vess Oil
in February 2010. Prior to joining Vess Oil, Mr. Hill spent
approximately ten years in the Energy Investment Banking group
of Raymond James and Associates, Inc., most recently as Vice
President, completing numerous public equity offerings, advisory
engagements and private securities assignments for a wide
spectrum of energy industry clients, including many exploration
and production companies. Mr. Hill earned his A.B. in
Economics with honors from Harvard College in 1998 and an M.B.A.
from the Darden Graduate School of Business at the University of
Virginia in 2003.
VOC-3
Alan Howarter is the Vice President of Financial
Reporting for Vess Oil responsible for the financial reporting
aspects of Vess Oil and other related entities.
Mr. Howarter joined Vess Oil in 2007. Prior to joining Vess
Oil, Mr. Howarter was a Manager at Regier Carr &
Monroe, L.L.P. Previously, Mr. Howarter was a Partner and
head of the Audit Department of the Wichita office of Grant
Thornton, LLP. Mr. Howarter received his Bachelor of
Business Administration degree in Accounting from Wichita State
University in 1978. He is a licensed CPA in Kansas.
Mr. Howarter is currently a member of the Accounting
Advisory Board of Wichita State University, the American
Institute of Certified Public Accountants, the Kansas Society of
Certified Public Accountants and the Petroleum Accountants
Society of Kansas. He is also a past president and treasurer of
the Petroleum Accountants Society of Kansas.
LITIGATION
VOC Sponsor is involved in legal actions and claims arising in
the ordinary course of business. Management does not expect
these matters to have a material adverse effect on the results
of operations or financial condition of VOC Sponsor.
INDEMNIFICATION
Under the partnership agreement of VOC Sponsor and subject to
specified limitations, Vess Texas Partners, LLC is not liable,
responsible or accountable in damages or otherwise to
VOC Sponsor or its members for, and VOC Sponsor will
indemnify and hold harmless Vess Texas Partners from any costs,
expenses, losses or damages (including attorneys fees and
expenses, court costs, judgments and amounts paid in settlement)
incurred by reason of its being the general partner of VOC
Sponsor.
RELATED
PARTY TRANSACTIONS
As of December 31, 2009, the VOC Operators, which includes
Vess Oil, L.D. Drilling, Inc. and Davis Petroleum, Inc.,
operated or operated on a contract basis, approximately 98% of
the total proved reserves attributable to the Underlying
Properties based on PV-10 value, with Vess Oil operating
approximately 90% of the total proved reserves for which VOC
Sponsor is the designated the operator and L.D. Drilling
Inc. and Davis Petroleum, Inc. operating approximately 8% of the
total proved reserves. Vess Oil is controlled by J. Michael
Vess, L.D. Drilling Inc. is controlled by L.D. Davis,
and Davis Petroleum, Inc., is controlled by both Mr. Vess
and Mr. Davis. Under the terms of the operating arrangement
among VOC Sponsor and Vess Oil, all expenses of Vess Oil
incurred on behalf of VOC Sponsor are paid by VOC Sponsor at the
cost incurred. Below is a summary of the transactions that
occurred between VOC Sponsor and the VOC Operators:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
Year Ended December 31,
|
|
September 30,
|
|
|
2007
|
|
2008
|
|
2009
|
|
2009
|
|
2010
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
Lease operating expenses incurred
|
|
$
|
10,002
|
|
|
$
|
11,734
|
|
|
$
|
10,723
|
|
|
$
|
7,946
|
|
|
$
|
8,377
|
|
Overhead costs included in lease operating expenses incurred
|
|
|
1,146
|
|
|
|
1,253
|
|
|
|
1,401
|
|
|
|
1,039
|
|
|
|
1,132
|
|
Capitalized lease equipment and producing leaseholds cost
incurred
|
|
|
1,882
|
|
|
|
1,926
|
|
|
|
2,094
|
|
|
|
1,132
|
|
|
|
2,863
|
|
Payment of well development costs
|
|
|
2,219
|
|
|
|
2,386
|
|
|
|
2,406
|
|
|
|
1,026
|
|
|
|
6,099
|
|
Payment of management fees
|
|
|
447
|
|
|
|
447
|
|
|
|
447
|
|
|
|
335
|
|
|
|
335
|
|
VOC Sponsor pays the VOC Operators an overhead fee based on a
monthly charge per active operated well to operate substantially
all of the Underlying Properties located in Kansas on behalf
VOC-4
of VOC Sponsor. The fee is adjusted annually and will increase
or decrease each year based on changes in the Overhead
Adjustment Index (OAI) published by the Council of
Petroleum Accountants Society for that year. The operating
activities include various maintenance, engineering, geological,
accounting and administrative functions. As reflected in the
summary reserve reports, in 2009, the aggregate overhead fee in
Kansas paid to the VOC Operators was approximately
$1.4 million.
For the Underlying Properties located in Texas, VOC Sponsor
reimburses Vess Texas Partners, LLC (Vess
LLC) for certain corporate administrative and
accounting services arranged by Vess LLC. This reimbursement
amount is adjusted annually and will increase or decrease each
year based on changes in the OAI for that year. Most of the
services for which Vess LLC is reimbursed are performed on
behalf of Vess LLC by Vess Oil. The fee is currently $37,250 per
month.
Vess LLC pays a portion of this $37,250 as an overhead fee to
Vess Oil to operate substantially all of the Underlying
Properties located in Texas on behalf of VOC Sponsor. The
operating activities include various maintenance, engineering,
geological, accounting and administrative functions. The
overhead fee includes (1) a fixed monthly charge of $13,500
per month, (2) reimbursement for certain geological and
engineering services and (3) a monthly charge per active
well brought on production after September 2009, which is
adjusted annual and based on changes in the Overhead Adjustment
Index.
Vess Oil is not contractually obligated to provide the corporate
administrative and accounting services on behalf of VOC Sponsor
or Vess LLC other than with respect to the operation of the
Underlying Properties, and VOC Sponsor and Vess LLC may contract
for the provision of the corporate administrative and accounting
services from other parties at any time. None of the members of
the executive management team are contractually obligated to
continue performing services on behalf of VOC Sponsor, and Vess
Oil is not contractually obligated to make its employees
available to perform such services.
The fees described above are independent of the fees payable by
the Trust pursuant to the trust agreement and the Administrative
Services Agreement. See The trust and
Description of the trust agreement Fees and
expenses.
For the nine-months ended September 30, 2010, VOC Sponsor
sold approximately 32% of the oil produced from the Underlying
Properties to MV Purchasing, LLC, an affiliate of VOC Sponsor. A
summary of sales and trade receivables with MV Purchasing
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended December 31,
|
|
|
September 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
Sales
|
|
$
|
|
|
|
$
|
1,207,358
|
|
|
$
|
13,482,074
|
|
|
$
|
9,176,357
|
|
|
$
|
14,185,601
|
|
Trade Receivables
|
|
$
|
|
|
|
$
|
319,109
|
|
|
$
|
1,359,842
|
|
|
|
|
|
|
$
|
1,410,080
|
|
MV Purchasing began operations on August 1, 2008.
Forty-five days following the closing of the initial public
offering of trust units, VOC Partners, LLC will
(1) purchase, at the initial offering price, trust units
owned by VOC Sponsor and (2) issue a promissory note to VOC
Sponsor having a face amount equal to 90% of the purchase price
for the trust units and a cash payment equal to 10% of the
purchase price for the trust units. The note will have a term of
ten years with interest payable at 5% per year.
VOC-5
SELECTED
HISTORICAL AND UNAUDITED PRO FORMA
FINANCIAL DATA OF VOC SPONSOR
The selected financial data presented below should be read in
conjunction with the accompanying financial statements and
related notes included elsewhere in this prospectus. In
connection with the closing of initial public offering of trust
units of VOC Energy Trust, pursuant to that certain Contribution
and Exchange Agreement dated August 30, 2010, VOC Brazos
will acquire all of the membership interests in KEP in exchange
for newly issued limited partnership interests in VOC Brazos,
resulting in KEP becoming a wholly-owned subsidiary of VOC
Brazos. As the Common Control Properties are deemed to be under
common control with VOC Brazos, accounting rules specify that
VOC Brazos and the Common Control Properties be combined
from the earliest date they came under common control. The
financial data and operations of such assets are referred to
herein as Predecessor, and are described in more
detail below in Managements discussion
and analysis of financial condition and results of
operations. Accordingly, in order to give full effect to
the acquisition by VOC Brazos of KEP, the following table
includes pro forma financial and operating data of Predecessor
giving effect to the acquisition of the Acquired Underlying
Properties. Since the historical assets and operations of
Predecessor will only represent a portion of the assets and
operations to be held by VOC Sponsor at the closing of this
offering, the future results of operations of VOC Sponsor will
not be comparable to the historical results of Predecessor.
The selected combined historical financial data of Predecessor
as of December 31, 2008 and 2009 and for each of the years
in the three-year period ended December 31, 2009 have been
derived from Predecessors audited financial statements.
The selected combined historical financial data of Predecessor
as of September 30, 2010 and for the nine-month periods
ended September 30, 2009 and 2010 have been derived from
Predecessors unaudited interim financial statements. The
unaudited financial statements were prepared on a basis
consistent with the audited statements and, in the opinion of
VOC Brazos, include all adjustments (consisting only of normal
recurring adjustments) necessary to present fairly the results
of Predecessor for the periods presented.
The selected unaudited pro forma financial data for the year
ended December 31, 2009 and as of and for the nine months
ended September 30, 2010 set forth in the following table
have been derived from the unaudited pro forma financial
statements of Predecessor included in this prospectus beginning
on
page VOC F-24.
The pro forma adjustments have been prepared as if the
acquisition of the Acquired Underlying Properties and, with
respect to pro forma as adjusted information, the offer and sale
of the trust units and application of the net proceeds
therefrom, had taken place (i) on September 30, 2010,
in the case of the pro forma balance sheet information as of
September 30, 2010, and (ii) as of January 1,
2009, in the case of the pro forma statement of
VOC-6
earnings information for the year ended December 31, 2009,
and the nine months ended September 30, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Pro Forma as
|
|
|
|
|
Predecessor Pro Forma for the
|
|
Adjusted for the Offering
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of the Acquired
|
|
(including the conveyance
|
|
|
|
|
|
|
|
|
|
|
|
|
Underlying Properties
|
|
of the Net Profits Interests)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
|
Nine Months
|
|
|
Predecessor
|
|
Year Ended
|
|
Ended
|
|
Year Ended
|
|
Ended
|
|
|
Year Ended December 31,
|
|
Nine Months Ended September 30,
|
|
December 31,
|
|
September 30,
|
|
December 31,
|
|
September 30,
|
|
|
2007
|
|
2008
|
|
2009
|
|
2009
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
2010
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
(Unaudited)
|
|
(Unaudited)
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
21,290
|
|
|
$
|
32,198
|
|
|
$
|
25,746
|
|
|
$
|
17,945
|
|
|
$
|
29,090
|
|
|
$
|
44,129
|
|
|
$
|
47,071
|
|
|
$
|
8,826
|
|
|
$
|
9,414
|
|
Interest income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sales of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,005
|
|
|
|
5,217
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
4
|
|
|
|
1
|
|
|
|
4
|
|
|
|
1
|
|
|
|
4
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
21,290
|
|
|
|
32,198
|
|
|
|
25,750
|
|
|
|
17,949
|
|
|
|
29,091
|
|
|
|
44,133
|
|
|
|
47,072
|
|
|
|
15,835
|
|
|
|
14,633
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
6,586
|
|
|
|
7,667
|
|
|
|
6,788
|
|
|
|
5,054
|
|
|
|
5,229
|
|
|
|
12,757
|
|
|
|
9,919
|
|
|
|
2,551
|
|
|
|
1,984
|
|
Production and property taxes
|
|
|
1,874
|
|
|
|
2,532
|
|
|
|
1,646
|
|
|
|
1,258
|
|
|
|
1,919
|
|
|
|
2,816
|
|
|
|
2,869
|
|
|
|
563
|
|
|
|
574
|
|
Depreciation, depletion, amortization and accretion
|
|
|
2,259
|
|
|
|
5,781
|
|
|
|
5,210
|
|
|
|
4,325
|
|
|
|
4,355
|
|
|
|
10,094
|
|
|
|
7,724
|
|
|
|
2,246
|
|
|
|
1,756
|
|
Bad debt expense (recovery)
|
|
|
|
|
|
|
1,727
|
|
|
|
(719
|
)
|
|
|
(719
|
)
|
|
|
|
|
|
|
(719
|
)
|
|
|
|
|
|
|
(719
|
)
|
|
|
|
|
General and administrative
|
|
|
121
|
|
|
|
269
|
|
|
|
463
|
|
|
|
243
|
|
|
|
111
|
|
|
|
463
|
|
|
|
130
|
|
|
|
463
|
|
|
|
130
|
|
Interest
|
|
|
363
|
|
|
|
1,383
|
|
|
|
1,501
|
|
|
|
1,168
|
|
|
|
920
|
|
|
|
1,501
|
|
|
|
920
|
|
|
|
1,501
|
|
|
|
920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
11,203
|
|
|
|
19,359
|
|
|
|
14,889
|
|
|
|
11,329
|
|
|
|
12,534
|
|
|
|
26,912
|
|
|
|
21,562
|
|
|
|
6,606
|
|
|
|
5,363
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
$
|
10,087
|
|
|
$
|
12,839
|
|
|
$
|
10,861
|
|
|
$
|
6,620
|
|
|
$
|
16,557
|
|
|
$
|
17,222
|
|
|
$
|
25,510
|
|
|
$
|
9,230
|
|
|
$
|
9,269
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (at period end)
|
|
|
|
|
|
$
|
108,830
|
|
|
$
|
101,280
|
|
|
|
|
|
|
$
|
109,626
|
|
|
|
|
|
|
$
|
173,271
|
|
|
|
|
|
|
$
|
85,220
|
|
Long-term liabilities, excluding current maturities (at period
end)
|
|
|
|
|
|
$
|
37,018
|
|
|
$
|
28,315
|
|
|
|
|
|
|
$
|
26,765
|
|
|
|
|
|
|
$
|
28,822
|
|
|
|
|
|
|
$
|
102,264
|
|
Partners capital/Common Control owners equity
(deficit)
|
|
|
|
|
|
$
|
67,865
|
|
|
$
|
67,512
|
|
|
|
|
|
|
$
|
79,932
|
|
|
|
|
|
|
$
|
139,876
|
|
|
|
|
|
|
$
|
(29,581
|
)
|
VOC-7
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS OF VOC SPONSOR
You should read the following discussion of the financial
condition and results of operations of VOC Sponsor in
conjunction with the historical consolidated financial
statements and notes included elsewhere in this prospectus.
For purposes of the following discussion in
Managements discussion and analysis of financial
condition and results of operations of VOC Sponsor, all
references herein to VOC Sponsor are intended to
mean the Predecessor and without giving effect to the
acquisition of the Acquired Underlying Properties. For more
information about the presentation of the Predecessor financial
statements, please see Note A to the combined financial
statements of Predecessor beginning on page
VOC F-1.
FACTORS
THAT SIGNIFICANTLY AFFECT VOC SPONSORS RESULTS
VOC Sponsors revenue, cash flow from operations and future
growth depend substantially on factors beyond its control, such
as economic, political and regulatory developments and
competition from producers of alternative sources of energy. Oil
and natural gas prices have historically been volatile and may
fluctuate widely in the future. Sustained periods of low prices
for oil or natural gas could materially and adversely affect its
financial position, its results of operations, the quantities of
oil and natural gas that it can economically produce and its
ability to access capital.
Like all businesses engaged in the exploration and production of
oil and natural gas, VOC Sponsor faces the challenge of
natural production declines. As initial reservoir pressures are
depleted, oil and natural gas production from a given well
decreases. Thus, an oil and gas exploration and production
company depletes part of its asset base with each unit of oil or
natural gas it produces. VOC Sponsor attempts to reduce this
natural decline by undertaking field development programs and by
implementing secondary recovery techniques. VOC Sponsor intends
to maintain its focus on costs necessary to produce its
reserves. VOC Sponsors ability to make development
expenditures to maintain production from its existing reserves
and to add reserves through development drilling is dependent on
its capital resources and can be limited by many factors.
VOC-8
RESULTS
OF OPERATIONS
Set forth in the table below is a summary of VOC Sponsors
financial data for the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Years Ended December 31,
|
|
|
September 30
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
21,290
|
|
|
$
|
32,198
|
|
|
$
|
25,746
|
|
|
$
|
17,945
|
|
|
$
|
29,090
|
|
Interest income
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
4
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
$
|
21,290
|
|
|
$
|
32,198
|
|
|
$
|
25,750
|
|
|
$
|
17,949
|
|
|
$
|
29,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
6,586
|
|
|
|
7,667
|
|
|
|
6,788
|
|
|
|
5,054
|
|
|
|
5,229
|
|
Production and property taxes
|
|
|
1,874
|
|
|
|
2,532
|
|
|
|
1,646
|
|
|
|
1,258
|
|
|
|
1,919
|
|
Depreciation, depletion, amortization and accretion
|
|
|
2,259
|
|
|
|
5,781
|
|
|
|
5,210
|
|
|
|
4,325
|
|
|
|
4,355
|
|
Bad debt expense (recovery)
|
|
|
|
|
|
|
1,727
|
|
|
|
(719
|
)
|
|
|
(719
|
)
|
|
|
|
|
General and administrative
|
|
|
121
|
|
|
|
269
|
|
|
|
463
|
|
|
|
243
|
|
|
|
111
|
|
Interest
|
|
|
363
|
|
|
|
1,383
|
|
|
|
1,501
|
|
|
|
1,168
|
|
|
|
920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
$
|
11,203
|
|
|
$
|
19,359
|
|
|
$
|
14,889
|
|
|
$
|
11,329
|
|
|
$
|
12,534
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
$
|
10,087
|
|
|
$
|
12,839
|
|
|
$
|
10,861
|
|
|
$
|
6,620
|
|
|
$
|
16,557
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2010 Compared To Nine Months
Ended September 30, 2009
The financial information with respect to the nine months ended
September 30, 2010 and 2009 that is discussed below is
unaudited. In the opinion of VOC Sponsors management, this
information contains all adjustments, consisting only of
adjustments for normally recurring accruals, necessary for a
fair presentation of the results for such periods. The results
of operations for these interim periods are not necessarily
indicative of the results of operations for the full fiscal year.
Revenues. Revenues from oil and natural gas
sales increased $11.1 million between these periods. This
consists of an increase of $13.1 million of oil and natural
gas revenues and a $2.0 million increase in hedge expense.
The $13.1 million increase in revenues was primarily the
result of an increase in the average price received for the oil
sold from $50.37 per Bbl for the nine months ended
September 30, 2009 to $73.15 per Bbl for the nine months
ended September 30, 2010 and a 76.1 MBbl increase in
oil volumes sold. The increase in revenues was also the result
of an increase in the average price received for the natural gas
sold from $3.36 per Mcf for the nine months ended
September 30, 2009 to $5.49 per Mcf for the nine months
ended September 30, 2010, and a 28.2 Mmcf increase in
natural gas volumes sold.
The increase in overall production sales volumes during the nine
months ended September 30, 2010 compared to the nine months
ended September 30, 2009 is primarily attributable to the
drilling of five horizontal wells in the Texas properties. One
well was drilled in the fourth quarter of 2009 and four were
drilled in the first nine months of 2010.
The increase in hedge activity expense of $2.0 million for
the nine months ended September 30, 2010 was due to an
increase in realized hedge losses and was partially offset by a
VOC-9
small increase in ineffectiveness of hedges then in place being
recorded to the income account for the period.
The increase in hedge expense was due to the higher average
NYMEX price per Bbl of crude oil for the first nine months of
2010 of $77.65 compared to $57.00 for the first nine months of
2009. The weighted average settlement price of hedges and other
derivatives for the first nine months of 2010 was $73.06
compared to $68.85 for the first nine months of 2009.
In addition, at September 30, 2010, VOC Sponsor recorded a
$0.4 million income for ineffectiveness of hedges compared
to no expense at September 30, 2009. At September 30,
2009, VOC Sponsor had open swap agreements covering the next
27 months. At September 30, 2010, VOC Sponsor had open
swap agreements covering the next 15 month periods
Hedge ineffectiveness of the swap agreements is the result of
various factors including changes in the average crude oil price
and changes in the basis differential between the NYMEX price
and the price actually received by VOC Sponsor.
Hedge ineffectiveness and actual hedge losses increased during
the period of rising oil prices as experienced from 2009 to 2010
when the average NYMEX price per barrel of crude oil went from
$41.92 to $75.55. Hedge ineffectiveness and hedge losses
typically decrease during periods of flat or declining oil
prices. Because commodity prices can fluctuate significantly,
past performance of VOC Sponsors hedges is not necessarily
indicative of their future performance.
Prices. The average price received for sales
of crude oil increased primarily as a result of an increase in
the oil price index on which the sales prices for a majority of
the oil production were based. The average price for natural gas
sold increased slightly as a result of an increase in the
natural gas price index on which the sales prices for a majority
of the natural gas production were based.
Lease operating expenses. Lease operating
expenses increased from $5.1 million for the nine months
ended September 30, 2009 to $5.2 million for the nine
months ended September 30, 2010. This increase was
primarily a result of an increase in production and property tax
expense due to the increased price of oil and gas on which the
taxes are based and casing repair to several wells, repair and
cleanout of a salt water disposal system well and continuing
restoration of wells from inactive status to producing status.
Production and property taxes. Production and
property taxes increased from $1.3 million for the nine
months ended September 30, 2009 to $1.9 million for
the nine months ended September 30, 2010. Production and
property taxes increased primarily as a result of the increases
in the price of crude oil and in revenues from oil and natural
gas sales, on which these taxes are based.
Depreciation, depletion, amortization and
accretion. Depreciation, depletion, amortization
and accretion increased from $4.3 million for the nine
months ended September 30, 2009 to $4.4 million for
the nine months ended September 30, 2010. Depreciation,
depletion and amortization are calculated based on units of
production. The increase comes from the addition of lease and
well equipment for the new wells drilled in 2010 and is
partially offset by the previously reduced asset base combined
with an increase in the total estimated reserves.
Bad debt expense (recovery). During the nine
months ended September 30, 2009, recovery was made of the
$1.4 million due for the Texas Underlying Properties. As a
result of the recovery, VOC Sponsor recorded bad debt recovery
of $0.7 million which reverses the bad debt expense
VOC-10
which was recorded in 2008. There was no bad debt recovery
during the nine months ended September 30, 2010.
As publicly reported on July 22, 2008, the revenue
intermediary/crude oil purchaser Eaglwing L.P., a revenue
intermediary/crude oil purchase for Predecessor, and its parent
(SemGroup, L.P.) filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code.
During this process, the monies that had been transferred to the
revenue intermediary by certain of Predecessors oil and
gas purchasers for distribution to Predecessor and other working
interest, royalty interest and overriding royalty interest
owners were erroneously retained by the revenue intermediary.
Vess Oil, as primary operator of Predecessors oil and gas
leases, filed suit to recover these funds which were estimated
to be $1.4 million for Predecessors ownership of the
Texas Underlying Properties. In addition, Vess Oil filed a proof
of claim for a statutory lien claim with the bankruptcy court on
behalf of the working interest owners (inclusive of Predecessor
interests), overriding royalty owners and royalty owners. In
2008, as there was no assurance as to the dollar amount, if any,
that would be recovered or the timing of such recovery, an
allowance for doubtful accounts of $0.7 million, or 50% of
the total estimated amount owed from Eaglwing, L.P. to
Predecessor for the Texas Underlying Properties, was established
as of December 31, 2008. In addition, an allowance was set
up for the oil purchased from the Kansas Underlying Properties
in the amount of $1.0 million which represents
approximately 87% of June 2008 sales made to Eaglwing, L.P.
General and administrative expenses. General
and administrative expenses decreased from $0.2 million for
the nine months ended September 30, 2009 to
$0.1 million for the nine months ended September 30,
2010. This decrease is primarily due to the timing of expenses
and a reduction of general costs.
Interest expense. Interest expense decreased
from $1.2 million for the nine months ended
September 30, 2009 to $0.9 million for the nine months
ended September 30, 2010. This is primarily a result of
principal payments made on outstanding indebtedness during 2009
in addition to a reduction of interest rates. During the nine
months ended September 30, 2009, VOC Sponsors
outstanding debt balance decreased from $30.0 million to
$24.0 million, while during the nine months ended
September 30, 2010, its outstanding debt balance was
$24.0 million.
Year
Ended December 31, 2009 Compared To The Year Ended
December 31, 2008
Revenues. Revenues from oil and natural gas
sales decreased $6.4 million between these periods. This
consists of a decrease of $15.7 million of oil and natural
gas revenues and was partially offset by a $9.3 million
decrease in hedge expense. The $15.7 million decrease in
revenues was primarily the result of a decrease in the average
price received for the oil sold from $94.11 per Bbl for the year
ended December 31, 2008 to $55.88 per Bbl for the year
ended December 31, 2009. The decrease in revenues was also
the result of a decrease in the average price received for the
natural gas sold from $7.86 per Mcf for the year ended
December 31, 2008 to $3.64 per Mcf for the year ended
December 31, 2009.
The decrease in hedge activity expense of $9.3 million for
the year ended December 31, 2009 was due primarily to the
lower average NYMEX settle price for the year ended
December 31, 2009 of $61.80 compared to $99.65 for the year
ended December 31, 2008. The weighted average hedge price
for 2009 was $68.85 compared to $70.02 for 2008.
Lease operating expenses. Lease operating
expenses decreased from $7.7 million for the year ended
December 31, 2008 to $6.8 million for the year ended
December 31, 2009. This decrease was primarily the result
of the electronification of wells in the Texas properties. The
operator started replacing the inefficient gas pumping motors in
the Texas properties with
VOC-11
electronic motors which can be shut-off and restarted during the
day as needed. This process also reduces wear on the moving
parts of the well thereby reducing repairs and maintenance costs.
Production and property taxes. Production and
property taxes decreased from $2.5 million for the year
ended December 31, 2008 to $1.6 million for the year
ended December 31, 2009. Production and property taxes
decreased primarily as a result of the decreases in the price of
crude oil and in revenues from oil and natural gas sales on
which these taxes are based.
Depreciation, depletion, amortization and
accretion. Depreciation, depletion, amortization
and accretion decreased from $5.8 million for the year
ended December 31, 2008 to $5.2 million for the year
ended December 31, 2009. Depreciation, depletion and
amortization are calculated based on units of production. The
decline comes from the previously reduced asset base combined
with an increase in the total estimated reserves.
Bad debt expense (recovery). During the year
ended December 31, 2008, as there was no assurance as to
the dollar amount, if any, that would be recovered or the timing
of such recovery, an allowance for doubtful accounts of
$0.7 million, or 50% of the total estimated amount owed
from Eaglwing, L.P. to Predecessor for the Texas Underlying
Properties, was established as of December 31, 2008. In
addition, an allowance was set up for the oil purchased from the
Kansas Underlying Properties in the amount of $1.0 million,
which represents approximately 87% of June 2008 sales made to
Eaglwing, L.P.
During the year ended December 31, 2009, recovery was made
of the $1.4 million due for the Texas Properties. As a
result of the recovery, VOC Sponsor recorded bad debt recovery
of $0.7 million, which reverses the bad debt expense which
was recorded in 2008.
General and administrative expenses. General
and administrative expenses increased from $0.3 million for
the year ended December 31, 2008 to $0.5 million for
the year ended December 31, 2009. This is an increase
primarily due to inflation in general costs.
Interest expense. Interest expense increased
from $1.4 million for the year ended December 31, 2008
to $1.5 million for the year ended December 31, 2009.
This is a result of borrowings of $1.1 million that took
place in April of 2008, $30.0 million that took place in
July of 2008 and $1.5 million that took place in August
2008 and carrying a balance through the entire year of 2009. The
interest expense was also affected by the decrease in interest
rates from the year ended December 31, 2008 to the year
ended December 31, 2009.
Year
Ended December 31, 2008 Compared To The Year Ended
December 31, 2007
Revenues. Revenues from oil and natural gas
sales increased $10.9 million between these periods. This
consists of an increase of $11.4 million of oil and natural
gas revenues which was partially offset by a $0.5 million
increase in hedge expense. The $11.4 million increase in
revenues was primarily the result of an increase in the average
price received for the oil sold from $67.31 per Bbl for the year
ended December 31, 2007 to $94.11 per Bbl for the year
ended December 31, 2008. The increase in revenues was also
the result of an increase in the average price received for the
natural gas sold from $6.39 per Mcf for the year ended
December 31, 2007 to $7.86 per Mcf for the year ended
December 31, 2008.
The increase in hedge activity expense of $0.5 million for
the year ended December 31, 2008 was due primarily to the
higher average NYMEX settle price for the year ended
December 31, 2008 of $99.65 compared to $72.34 for the year
ended December 31, 2007. The weighted average hedge price
for 2008 was $70.02 compared to $52.27 for 2007.
VOC-12
Lease operating expenses. Lease operating
expenses increased from $6.6 million for the year ended
December 31, 2007 to $7.7 million for the year ended
December 31, 2008. This increase was primarily a result of
the purchase of oil and gas leaseholds in August of 2008 along
with general increased costs of primary vendors who rely on
large uses of hydrocarbon products such as (1) pumpers
(gasoline), (2) utilities (cost of fuel), (3) treating
chemicals (hydrocarbon base) and (4) pulling units (fuel
surcharge). This increase was also supplemented by wage
increases associated with the increased demand for oilfield
employees and increases in the price of steel for tubular and
other metal products.
Production and property taxes. Production and
property taxes increased from $1.9 million for the year
ended December 31, 2007 to $2.5 million for the year
ended December 31, 2008. Production and property taxes
increased primarily as a result of the increases in the price of
crude oil and in revenues from oil and natural gas sales, on
which these taxes are based.
Depreciation, depletion, amortization and
accretion. Depreciation, depletion, amortization
and accretion increased from $2.3 million for the year
ended December 31, 2007 to $5.8 million for the year
ended December 31, 2008. Depreciation, depletion and
amortization are calculated based on units of production. The
increase in depreciation, depletion and amortization was
primarily the result of the addition of oil and gas leaseholds,
lease and well equipment and well development that add to the
asset base combined with a decrease in the total estimated
reserves.
Bad debts expense (recovery). During the year
ended December 31, 2008, as there was no assurance as to
the dollar amount, if any, that would be recovered or the timing
of such recovery, an allowance for doubtful accounts of
$0.7 million, or 50% of the total estimated amount owed
from Eaglwing, L.P. to Predecessor for the Texas Underlying
Properties, was established as of December 31, 2008. In
addition, an allowance was set up for the oil purchased from the
Kansas Properties in the amount of $1.0 million, which
represents approximately 87% of June 2008 sales made to
Eaglwing, L.P.
During the year ended December 31, 2007, there was no bad
debt expense or recovery.
General and administrative expenses. General
and administrative expenses increased from $0.1 million for
the years ended December 31, 2007 to $0.3 million for
the year ended December 31, 2008. This was primarily the
result of increased costs due to the purchase of oil and gas
leaseholds in August of 2008 along with increases in these costs
due to inflationary adjustments.
Interest expense. Interest expense increased
$1.0 million from $0.4 million for the year ended
December 31, 2007 to $1.4 million for the year ended
December 31, 2008. This is a result of borrowings of
$1.1 million that took place in April of 2008,
$30.0 million that took place in July of 2008 and
$1.5 million that took place in August of 2008.
LIQUIDITY
AND CAPITAL RESOURCES
VOC Sponsors primary sources of capital and liquidity have
been proceeds from sales of partnership interests, borrowings
under its bank credit facility and cash flow from operations. To
date, its primary uses of capital have been to service its debt
requirements, for development of working interests in its oil
and natural gas properties located in Kansas and Texas and for
distributions. It continually monitors its capital resources
available to meet its future financial obligations and planned
development expenditures.
VOC-13
Cash
Flow from Operating Activities
Net cash provided by operating activities was $9.9 million
and $21.1 million for the nine months ended
September 30, 2009 and 2010, respectively. The increase in
net cash provided by operating activities was due substantially
to increases in the price of oil and sales volumes.
Net cash provided by operating activities was $15.0 million
during the year ended December 31, 2009, compared to
$15.8 million during the year ended December 31, 2009.
The increase in net cash provided by operating activities in
2009 was substantially due to decreased expenses partially
offset by decreased revenues, as discussed above in
Results of Operations.
VOC Sponsors cash flow from operations is subject to many
variables, the most significant of which are 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 its control. VOC Sponsors future cash flow from
operations will depend on its ability to maintain and increase
production through its development program, as well as the
prices of oil and natural gas.
VOC Sponsor has entered into certain hedge contracts related to
the oil production from the Underlying Properties for 2011 at a
strike price of $94.90 per barrel of oil that hedge
approximately 22% expected production from the proved developed
producing reserves attributable to the Underlying Properties in
the reserve reports. The hedge contracts will not be pledged to
the trust, but any payments made by VOC Sponsor upon settlement
of the hedge contracts will be factored into the calculation of
the net proceeds from the Underlying Properties. Any proceeds
received by VOC Sponsor upon settlement of the hedge contracts
will separately be factored into the calculation of payment due
to the trust. From January 1, 2011 through
December 31, 2011, VOC Sponsors crude oil price risk
management position in swap contracts is as follows:
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Fixed Price Swaps
|
|
|
|
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Weighted
|
|
|
Volumes
|
|
Average Price
|
Month
|
|
(Bbls)
|
|
(Per Bbl)
|
|
January 2011
|
|
|
13,689
|
|
|
$
|
94.90
|
|
February 2011
|
|
|
13,621
|
|
|
$
|
94.90
|
|
March 2011
|
|
|
13,553
|
|
|
$
|
94.90
|
|
April 2011
|
|
|
13,486
|
|
|
$
|
94.90
|
|
May 2011
|
|
|
13,420
|
|
|
$
|
94.90
|
|
June 2011
|
|
|
13,354
|
|
|
$
|
94.90
|
|
July 2011
|
|
|
13,289
|
|
|
$
|
94.90
|
|
August 2011
|
|
|
13,224
|
|
|
$
|
94.90
|
|
September 2011
|
|
|
13,160
|
|
|
$
|
94.90
|
|
October 2011
|
|
|
13,096
|
|
|
$
|
94.90
|
|
November 2011
|
|
|
13,032
|
|
|
$
|
94.90
|
|
December 2011
|
|
|
12,970
|
|
|
$
|
94.90
|
|
By removing the price volatility from a significant portion of
its oil production, VOC Sponsor has mitigated, but not
eliminated, the potential effects of changing commodity prices
on its cash flow from operations for those periods. While
mitigating negative effects of falling crude oil prices, these
derivative contracts also limit the benefits VOC Sponsor would
receive from increases in crude oil prices. It is VOC
Sponsors policy to enter into derivative contracts only
with counterparties that are major, creditworthy financial
institutions deemed by management as competent and competitive
market makers.
VOC-14
Cash
Flows from Investing Activities
VOC Sponsors development expenditures were
$1.8 million and $7.7 million for the nine months
ended September 30, 2009 and 2010, respectively. Capital
expenditures for each of the nine months ended
September 30, 2009 and September 30, 2010 includes the
purchase of oil and natural gas properties and the payment of
well development costs.
VOC Sponsors development expenditures were
$7.9 million in the year ended December 31, 2008 and
$3.7 million in the year ended December 31, 2009. The
total for 2009 includes the purchase of oil and natural gas
properties and the payment of well development costs.
VOC Sponsor currently anticipates that its development
budget, which predominantly consists of workover drilling,
secondary recovery projects and equipment, will be
$8.0 million for the remainder of 2010 and 2011. The amount
and timing of its development expenditures is largely
discretionary and within its control. VOC Sponsors
routinely monitors and adjusts its development expenditures in
response to changes in oil and natural gas prices, development
costs, industry conditions and internally generated cash flow.
Future cash flows are subject to a number of variables,
including the level of production and prices. There can be no
assurance that operations and other capital resources will
provide cash in sufficient amounts to maintain planned levels of
development expenditures.
Financing
Activities
Credit
facility
On June 27, 2008, VOC Sponsor entered into a bank credit
facility with a group of bank lenders that provides for a
revolving line of credit, letters of credit and swing line
loans. The total amount that VOC Sponsor can borrow and have
outstanding at any one time is limited to the lesser of the
total commitment of $100 million or the borrowing base
established by the lenders. As of September 30, 2010, the
borrowing base under the bank credit facility was
$37.0 million. As of September 30, 2010, the principal
amount outstanding under the bank credit facility was
$24.0 million with no letters of credit or swing line loans
outstanding.
The bank credit facility allows VOC Sponsor to borrow, repay and
reborrow amounts available under the bank credit facility. The
amount of the borrowing base is based primarily upon the
estimated value of VOC Sponsors oil and natural gas
reserves. The borrowing base under the bank credit facility is
subject to re-determination at least semi-annually. The bank
credit facility matures on June 27, 2013, and borrowings
under the bank credit facility bear interest, payable quarterly,
at VOC Sponsors option, at (1) a rate (as defined and
further described in the bank credit facility) per annum equal
to a Eurodollar Rate (which is substantially the same as the
London Interbank Offered Rate) for one, two, three or six months
as offered by the lead bank under the bank credit facility or
(2) the higher of the Federal Funds Rate (as defined and
further described in the bank credit facility) plus
50 basis points or such banks Prime Rate.
VOC Sponsors bank credit facility bore interest at
2.19% per annum as of September 30, 2010. VOC Sponsor pays
quarterly commitment fees under the bank credit facility on the
unused portion of the available borrowing base at ranging from
25.0 to 50.0 basis points, dependent upon the percentage of
VOC Sponsors available borrowing base then utilized.
Borrowings under the bank credit facility are secured by a lien
on substantially all of VOC Sponsors assets and
properties in Texas. The bank credit facility also contains
restrictive covenants that may limit VOC Sponsors ability
to, among other things, pay dividends, incur additional
indebtedness, sell assets, make loans to others, make
investments, enter into mergers, incur liens and engage in
certain other transactions without the prior consent of the
lenders. The bank credit facility also requires VOC Sponsor to
maintain certain ratios as defined and further
VOC-15
described in the revolving credit facility, including a current
ratio of not less than 1.0 to 1.0, an interest coverage ratio
not less than 2.5 to 1.0 and a maximum leverage ratio of no
greater than 3.5 to 1.0. The current ratio is defined to include
the amount of the unused borrowing base as a current asset and
to exclude current maturities of the credit facility as well as
any current liability resulting from any mark to market
accounting under accounting literature. In addition,
VOC Sponsor was required to enter into swap agreements
covering 75% of estimated production for the three years
following December 31, 2008 based on proved reserves as of
December 31, 2007, with a fixed price per barrel. As of
September 30, 2010, VOC Sponsor was in compliance with all
such covenants.
CONTRACTUAL
OBLIGATIONS
A summary of VOC Sponsors contractual obligations as of
September 30, 2010 is provided in the following table.
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|
|
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|
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|
|
|
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|
|
Payments Due by Period
|
|
|
|
|
|
|
Less Than
|
|
|
|
|
|
|
|
|
More Than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
|
(In thousands)
|
|
|
Long-term debt (a)
|
|
$
|
24,000
|
|
|
$
|
|
|
|
$
|
24,000
|
|
|
$
|
|
|
|
$
|
|
|
Asset retirement obligation
|
|
|
5,246
|
|
|
|
424
|
|
|
|
230
|
|
|
|
285
|
|
|
|
4,307
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
29,246
|
|
|
$
|
424
|
|
|
$
|
24,230
|
|
|
$
|
285
|
|
|
$
|
4,307
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The amounts included in the table
above represent principal maturities only. See
Managements discussion and analysis of financial
condition and results of operations of VOC Sponsor
Quantitative and qualitative disclosure about market
risk Interest rate risk for information
regarding interest payment obligations under long-term debt
obligations.
|
OFF-BALANCE
SHEET ARRANGEMENTS
As of September 30, 2010, VOC Sponsor had no off-balance
sheet arrangements and currently has no intention to establish
any off-balance sheet arrangements.
CRITICAL
ACCOUNTING POLICIES AND ESTIMATES
The discussion and analysis of VOC Sponsors historical
financial condition and results of operations is based upon its
consolidated financial statements, which have been prepared in
accordance with accounting principles generally accepted in the
United States. The preparation of these financial statements
requires it to make estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses,
and related disclosure of contingent assets and liabilities.
Certain accounting policies involve judgments and uncertainties
to such an extent that there is reasonable likelihood that
materially different amounts could have been reported under
different conditions, or if different assumptions had been used.
VOC Sponsor evaluates its estimates and assumptions on a
regular basis. It bases its estimates on historical experience
and various other assumptions that are believed to be reasonable
under the circumstances, the results of which form the basis for
making judgments about the carrying values of assets and
liabilities that are not readily apparent from other sources.
Actual results may differ from these estimates and assumptions
used in preparation of its financial statements. VOC Sponsor has
provided below an expanded discussion of its more significant
accounting policies, estimates and judgments. It believes these
accounting policies reflect its more significant estimates and
assumptions used in the preparation of its financial statements.
Please read Note A of the Notes to the Financial Statements
of VOC Sponsor beginning on page VOC F-1 for a discussion of
additional accounting policies and estimates made by its
management.
VOC-16
Oil
and Natural Gas Properties
VOC Sponsor accounts for oil and natural gas properties by the
successful efforts method rather than the full cost method. The
most significant difference between the successful efforts
method of accounting and the full cost method is that, under the
successful efforts method, geological, geophysical and dry hole
costs on oil and natural gas properties relating to unsuccessful
wells are charged to expense and against earnings as incurred
and expenses associated with successfully locating new oil and
natural gas reserves are capitalized; whereas, under the full
cost method of accounting, such costs and expenses of
unsuccessful projects are capitalized as assets, pooled with the
costs of successful wells and charged against the earnings of
future periods as a component of depletion expense.
Leasehold acquisition costs are capitalized. If proved reserves
are found on an undeveloped property, leasehold cost is
transferred to proved properties. Under this method of
accounting, costs relating to the development of proved areas
are capitalized when incurred.
Revenues from the sale of oil and gas production are recognized
as oil and gas is produced and sold.
Depreciation and depletion of producing oil and natural gas
properties is recorded based on units of production. Unit rates
are computed for unamortized drilling and development costs
using proved developed reserves and for unamortized leasehold
costs using all proved reserves. Financial Accounting Standards
Board (FASB) Accounting Standards Codification
(ASC) 932 Extractive
Industries Oil and Gas requires that acquisition
costs of proved properties be amortized on the basis of all
proved reserves, developed and undeveloped, and that capitalized
development costs (wells and related equipment and facilities)
be amortized on the basis of proved developed reserves. As more
fully described in Note K of the Notes to the Combined
Financial Statements, proved reserves are estimated by an
independent petroleum engineer, Cawley, Gillespie &
Associates, Inc., and are subject to future revisions based on
availability of additional information. As described in
Note G of the Notes to the Combined Financial Statements,
VOC Sponsor follows FASB ASC 410 Asset
Retirement and Environmental Obligations. Under FASB
ASC 410, estimated asset retirement costs are recognized
when the asset is placed in service and are amortized over
proved reserves using the units of production method. Asset
retirement costs are estimated by its engineers using existing
regulatory requirements and anticipated future inflation rates.
Property acquisition costs, if any, are capitalized when
incurred. Upon sale or retirement of complete fields of
depreciable or depleted property, the book value thereof, less
proceeds or salvage value, is credited to income. On sale or
retirement of an individual well, the proceeds are credited to
accumulated depreciation and depletion.
VOC Sponsor assesses its oil and natural gas properties for
possible impairment when facts and circumstances indicate that
their carrying value may not be recoverable. Such indicators
include changes in the companys business plans, changes in
commodity prices and, for crude oil and natural gas properties,
significant downward revisions of estimated proved-reserve
quantities. Unproven properties that are individually
significant are assessed for impairment and if considered
impaired are charged to expense when such impairment is deemed
to have occurred. VOC Sponsor assesses impairment of capitalized
costs of proved oil and natural gas properties by comparing net
capitalized costs to estimated undiscounted future net cash
flows using expected prices. If net capitalized costs exceed
estimated undiscounted future net cash flows, the measurement of
impairment is based on estimated fair value, which would
consider estimated future discounted cash flows. Determination
as to whether and how much an asset is impaired involves
management estimates on highly uncertain matters such as future
commodity prices, the
VOC-17
effects of inflation and technology improvements on operating
expenses, production profiles, and the outlook for global or
regional market supply and demand conditions for crude oil,
natural gas, commodity chemicals and refined products. However,
the impairment reviews and calculations are based on assumptions
that are consistent with VOC Sponsors business plans and
long-term investment decisions. As of December 31, 2008 and
2009, and September 30, 2010, the estimated undiscounted
future cash flows for its proved oil and natural gas properties
exceeded the net capitalized costs, and no impairment was
required to be recognized.
Oil
and Natural Gas Reserve Quantities
VOC Sponsors estimate of proved reserves is based on the
quantities of oil and natural gas that engineering and
geological analyses demonstrate, with reasonable certainty, to
be recoverable from established reservoirs in the future under
current operating and economic parameters. Cawley,
Gillespie & Associates, Inc. prepares a reserve and
economic evaluation of all its properties on a
well-by-well
basis.
Reserves and their relation to estimated future net cash flows
impact VOC Sponsors depletion and impairment calculations.
As a result, adjustments to depletion and impairment are made
concurrently with changes to reserve estimates. VOC Sponsor
prepares its reserve estimates, and the projected cash flows
derived from these reserve estimates, in accordance with
SEC guidelines. The independent engineering firm described
above adheres to the same guidelines when preparing their
reserve reports. The accuracy of its reserve estimates is a
function of many factors, including the quality and quantity of
available data, the interpretation of that data, the accuracy of
various mandated economic assumptions and the judgments of the
individuals preparing the estimates.
VOC Sponsors proved reserve estimates are a function of
many assumptions, all of which could deviate significantly from
actual results. As such, reserve estimates may materially vary
from the ultimate quantities of oil and natural gas eventually
recovered.
Hedging
Activities
VOC Brazos periodically uses derivative financial instruments to
achieve a more predictable cash flow from its oil production by
reducing its exposure to fluctuations in the price of crude oil.
Currently, these transactions are swaps transactions. VOC Brazos
accounts for these activities pursuant to FASB
ASC 815 Derivatives and Hedging, which requires
that derivative instruments (including certain derivative
instruments embedded in other contracts) be recorded at fair
market value and included in the balance sheet as assets or
liabilities.
The accounting for changes in the fair market value of a
derivative instrument depends on the intended use of the
derivative instrument and the resulting designation, which is
established at the inception of a derivative instrument. FASB
ASC 815 requires that a company formally document, at the
inception of a hedge, the hedging relationship and the
entitys risk management objective and strategy for
undertaking the hedge, including identification of the hedging
instrument, the hedged item or transaction, the nature of the
risk being hedged, the method that will be used to assess
effectiveness and the method that will be used to measure hedge
ineffectiveness of derivative instruments that receive hedge
accounting treatment.
For derivative instruments designated as cash flow hedges,
changes in fair market value, to the extent the hedge is
effective, are recognized in other comprehensive income until
the hedged item is recognized in earnings. Hedge effectiveness
is assessed at least quarterly based on total changes in the
derivative instruments fair market value. Any ineffective
portion of the derivative instruments change in fair
market value is recognized immediately in earnings.
VOC-18
Asset
Retirement Obligations
ASC 410 Asset Retirement and Environmental
Obligations requires that the fair value of a liability for an
asset retirement obligation be recognized in the period in which
it is incurred. The liability is measured at discounted fair
value and is adjusted to its present value in subsequent periods
as accretion expense is recorded. Such accretion expense is
included in depreciation, depletion and amortization in the
accompanying statements of earnings. The corresponding asset
retirement costs are capitalized as part of the carrying amount
of the related long-lived asset and amortized over the
assets useful life. VOC Sponsors asset retirement
obligations are primarily associated with the plugging of
abandoned oil wells.
NEW
ACCOUNTING PRONOUNCEMENTS
In January 2010, the FASB issued ASU
2010-04,
Accounting for Various Topics Technical
Corrections to SEC Paragraphs ASU
2010-04
makes technical corrections to existing SEC guidance, including
the following topics: accounting for subsequent investments,
termination of an interest rate swap, issuance of financial
statements subsequent events, use of residential
method to value acquired assets other than goodwill, adjustments
in assets and liabilities for holding gains and losses, and
selections of discount rate used for measuring defined benefit
obligation. The adoption of ASU
2010-04 did
not have a material impact on our financial statements.
In January 2010, the FASB issued ASU
2010-06,
Improving Disclosures about Fair Value Measurements
(ASU
2010-06),
which provides amendments to ASC topic Fair Value
Measurements and Disclosures. This will provide more
robust disclosures about (i) the different classes of
assets and liabilities measured at fair value, (ii) the
valuation techniques and inputs used, (iii) the activity in
Level 3 fair value measurements, and (iv) the
transfers between Levels 1, 2 and 3. ASU
2010-06 is
effective for fiscal years and interim periods beginning after
December 15, 2009. The adoption did not have a material
impact to our financial statements.
In February 2010, the FASB issued ASU
2010-09 (ASU
2010-09),
Subsequent Events (Topic 855). The amendments
remove the requirements for an SEC filer to disclose a date, in
both issued and revised financial statements, through which
subsequent events have been reviewed. Revised financial
statements include financial statements revised as a result of
either correction of an error or retrospective application of
U.S. GAAP. ASU
2010-09 is
effective for interim or annual financial periods ending after
June 15, 2010. Adoption of the provisions of ASU
2010-09 did
not have a material effect on our financial position, results of
operations or cash flows.
In April 2010, the FASB issued ASU
2010-14,
Accounting for Extractive Activities
Oil & Gas. ASU
2010-14
amends
paragraph 932-10-S99-1
due to SEC Release
No. 33-8995,
Modernization of Oil and Gas Reporting. The
amendments to the guidance on oil and gas accounting are
effective August 31, 2010, and did not have a significant
impact on our financial position.
On August 2, 2010, the FASB issued ASU
2010-21,
Accounting for Technical Amendments to Various SEC Rules
and Schedules Amendments to SEC
Paragraphs Pursuant to Release
No. 33-9026:
Technical Amendments to Rules, Forms, Schedules and Codification
of Financial Reporting Policies. The ASU reflects changes
made by the SEC in Final Rulemaking
Release No. 33-9026,
which was issued in April 2009 and amended SEC requirements in
Regulation S-X
and
Regulation S-K
and made changes to financial reporting requirements in response
to the FASBs issuance of SFAS No. 141(R),
Business Combinations (FASB ASC 805), and
SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements an
VOC-19
amendment of ARB No. 51 ( FASB ASC 810).
Adoption of ASU
2010-21 did
not have a material impact on our financial statements.
QUANTITATIVE
AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about
VOC Sponsors 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. This forward-looking information provides
indicators of how VOC Sponsor views and manages its ongoing
market risk exposures. All of its market risk sensitive
instruments were entered into for purposes other than
speculative trading.
Commodity
Price Risk
VOC Sponsors major market risk exposure is in the pricing
applicable to its oil and natural gas production. Realized
pricing is primarily driven by the spot market prices applicable
to its oil production and the prevailing price for natural gas.
Pricing for oil production has been volatile and unpredictable
for several years, and VOC Sponsor expects this volatility to
continue in the future. The prices it receives for oil and
natural gas production depend on many factors outside of its
control.
VOC Sponsor has entered into hedging arrangements with respect
to a portion of its projected oil production through various
transactions that hedge the future prices received. These
transactions are typically price swaps whereby it will receive a
fixed price for its production and pay a variable market price
to the contract counterparty. These hedging activities are
intended to support oil prices at targeted levels and to manage
its exposure to oil price fluctuations.
Based on an oil price of $79.97 per Bbl as of September 30,
2010, the fair value of its hedge positions for 2010 was a
receivable of $2.1 million, which it owed to the
counterparty. A 10% increase or decrease in the index oil
price above the September 30, 2010 price for oil would
increase or decrease the receivable by $1.6 million,
respectively.
Interest
Rate Risks
At September 30, 2010, VOC Sponsor had debt outstanding
under its bank credit facility and other long-term debt of
$24.3 million. The weighted average annual interest rate
under the bank credit facility for the nine months ended
September 30, 2010 was 2.46%. If prevailing market interest
rates had been 1% higher as of September 30, 2010, and all
other factors affecting VOC Sponsors debt remained
the same interest expense on an annual basis would have been
$0.2 million higher.
VOC-20
DESCRIPTION
OF THE VOC BRAZOS PARTNERSHIP AGREEMENT
The following is a summary of the material provisions of the
Amended and Restated Partnership Agreement of VOC Brazos Energy
Partners, L.P. (VOC Brazos), as amended. A copy
of the Amended and Restated Partnership Agreement of VOC Brazos
(the Partnership Agreement), as well as the
amendment thereto, is included as an exhibit to the registration
statement to which this prospectus forms a part.
ORGANIZATION
AND DURATION
VOC Brazos was organized as a Texas limited partnership on
May 21, 2003 and will remain in existence until dissolved
in accordance with the Partnership Agreement. See
Dissolution.
BUSINESS
The Partnership Agreement limits the business of VOC Brazos to:
(i) holding, maintaining, renewing, acquiring, exploring,
drilling, developing and operating oil and natural gas
properties, leases and wells; (ii) producing, collecting,
storing, treating, delivering, marketing, selling or otherwise
disposing of oil, gas and related hydrocarbons and minerals;
(iii) farming-out, selling, abandoning and otherwise
disposing of assets of VOC Brazos; (iv) entering into
swaps, options, future contracts and other transactions to hedge
or to otherwise minimize the risk associated with the
fluctuation of prices to be received by VOC Brazos from the sale
of oil, gas and related hydrocarbons and minerals; and
(v) taking all such other actions incidental to any of the
foregoing as the general partner of VOC Brazos may determine to
be necessary or appropriate.
DISTRIBUTION
OF AVAILABLE CASH
On or about the tenth day of the month immediately preceding the
due date for a payment of estimated income tax by an individual,
VOC Brazos will distribute an amount of cash which the general
partner reasonably estimates equals the product of
(a) maximum marginal combined federal, state, and local
income tax rates applicable to a single individual residing in
Kansas, and (b) the net taxable income of VOC Brazos (to
the extent an estimated income tax payment is or would be due by
a partner, directly or indirectly for the applicable
distribution period), to the extent of cash available for such
distribution and provided that such distribution (i) is not
prohibited by the terms of the Partnership Agreement and
(ii) would not create a default under the Texas Revised
Limited Partnership Act (the Texas LP Act) or any
agreement with an unrelated third party to which VOC Brazos is
subject. In making this determination the general partner is
entitled to rely on the books and records, IRS Form 1065
and
Schedule K-1s,
and such other information and advice as is reasonable available
at the time of the distribution. Distributions, income, gain,
loss, deduction and credits are generally allocated to the
partners pro rata in proportion their partnership
interests, subject to certain requirements and regulations
required by the Internal Revenue Code. All cash funds of VOC
Brazos available for distribution to its members will be after
giving effect to the obligation of VOC Brazos to pay 80% of the
net proceeds to the trust pursuant to the net profits interest.
For a more detailed description of the determination of
net proceeds, see Computation of net
proceeds.
MANAGEMENT
OF VOC BRAZOS AND FIDUCIARY DUTIES
The Partnership Agreement provides that the general partner of
VOC Brazos shall generally have complete and exclusive
discretion in managing and controlling the daily operations and
ordinary business of VOC Brazos in accordance with the
Partnership Agreement and to do or cause to be done any and all
acts deemed by the general partner to be necessary or
appropriate thereto.
VOC-21
The Partnership Agreement designates Vess Texas Partners, LLC as
the initial general partner. The Partnership Agreement further
provides that the general partner shall have no fiduciary duty
(including, but not limited to, any duty of loyalty or duty of
care) to VOC Brazos or any partner except (i) a duty to act
in good faith, (ii) a general obligation of fair dealing
with respect to VOC Brazos and the property of VOC Brazos,
(iii) any duty expressly set forth in the Partnership
Agreement, and (iv) any duty expressly set forth in other
written agreements of VOC Brazos. The general partner may
consult a professional staff and outside consultants. The
Partnership Agreement allows the general partner to possess
interests and engage in business activities in addition to those
relating to VOC Brazos, independently or with others, including
business interests and activities in direct competition with VOC
Brazos, and, subject to certain exceptions, neither
VOC Brazos nor the other partners have any right, title or
interest in or to such ventures.
The general partner is restricted from taking certain actions
without the approval or authorization of the holders of the
majority of the partnership interests, including (subject to
certain exceptions) the borrowing of money, mortgage or pledging
of property, selling, assigning, abandoning or otherwise
disposing of any lease of VOC Brazos, guaranteeing of
third-party payment or performance, making advance payments of
compensation or other consideration to the general partner or
the general partners affiliates, obligating the company
with respect to matters outside the scope of its business,
merging, consolidating or converting with or into any other
entity, loaning funds of VOC Brazos to the general partner or
the general partners affiliates, entering into hedging
transactions and amending or terminating any agreements or other
documents evidencing hedging transactions or waiving any of the
rights of VOC Brazos thereunder, making or approving well
expenditures or acquiring leases if the pro rata share to be
born by any indirect owner of a limited partner would exceed
$1 million, or compromising or settling any suit or dispute
for more than $100,000.
The general partner, partners, and any affiliates thereof are
restricted from retaining from or otherwise burdening the
interest in any lease of VOC Brazos with any overriding royalty
interest, net profits interest, carried interest, reversionary
interest, production payment or other burden in favor of itself,
its officers, directors and employees or any other person,
except in connection with an acquisition by the general partner,
member or such affiliate pursuant to a transaction where an
unrelated third party transferring the lease retains such an
interest or burden with respect to all of the lease being
acquired. Under no circumstances can the general partner,
limited partner or any affiliate acquire rights to any separate
horizon within or under a lease in which VOC Brazos has an
interest.
The general partner has the authority to cause VOC Brazos to
sell any oil or gas produced by or for the account of VOC Brazos
upon the best terms and conditions available, as determined in
good faith by the manager taking into account all relevant
circumstances, including but not limited to, price, quality of
production, access to markets, minimum purchase guarantees,
identity of purchaser, and length of commitment and, in any
event, on terms no less favorable to VOC Brazos than the general
partner or any affiliate thereof has recently obtained or is
obtaining for arms length sales, exchanges or dispositions
of the general partners or such affiliates
production of similar quantity and quality in the same
geographic area where VOC Brazos production is located.
The Partnership Agreement provides that Vess Oil Corporation
(Vess Oil) will serve as operator on behalf of
VOC Brazos in connection with operations on each lease held
by VOC Brazos included in the Underlying Properties that it is
operating as of the date of the Partnership Agreement unless a
third person is already designated as operator of that lease or
a third party that holds a controlling interest in that lease
will not consent to the designation of Vess Oil as operator. As
to those leases that Vess Oil is not designated as operator, the
general partner will take such actions and exercise such rights
and remedies that are reasonably available to it to
VOC-22
cause the actual operator to properly develop, maintain and
operate such leases. With respect to those leases for which Vess
Oil is designated as operator, Vess Oil, as the case may be,
shall be entitled to receive the compensation and reimbursement
to which the operator is entitled in accordance with the
provisions of the Partnership Agreement, which sets forth agreed
upon charges for certain direct expenses and material furnished
to, or transferred from or disposed of by the operator, or any
other operating agreement governing the operation of such lease.
Vess Oil may not substitute another party as operator or assign
its obligations with respect to any lease of VOC Brazos for
which it is designated as operator unless a majority of the
limited partners request, in connection with the removal of the
general partner, as such or the limited partners dissolve VOC
Brazos in accordance with the Partnership Agreement.
VOC Brazos pays an overhead fee to Vess Oil to drill, develop
and operate the underlying properties on behalf of VOC Brazos.
The overhead fee is based on a monthly charge for
administrative, supervision, officer services, overhead and
warehousing costs, including overhead costs incurred in the
construction and installation of fixed assets, the expansion of
fixed assets and other projects required for the development and
operation of the underlying properties of VOC Brazos that is
determined either (a) on the same terms and conditions as
Vess Oil charges unrelated parties, or (b) approved by
majority of its limited partners, with knowledge of the material
facts of the transaction and Vess Oils interest. The
overhead fee is adjusted annually and will increase or decrease
each year based on the Overhead Adjustment Index published by
the Council of Petroleum Accountants Society. VOC Brazos is
also directly responsible for all direct, third-party
out-of-pocket
expenses reasonably incurred on its behalf, including audit, tax
preparation and reserve report related expenses.
VOC Brazos has agreed to pay the general partner a monthly fee
of $37,250 for management-related services provided to VOC
Brazos.
LIMITED
LIABILITY
The limited partners of VOC Brazos are not liable for the debts,
liabilities, contracts or other obligations of VOC Brazos under
the Partnership Agreement. Moreover, VOC Brazos agrees to
indemnify and hold harmless the general partner, the limited
partners, their affiliates, and all of their officers,
directors, trustees, partners, principals, employees and agents
(the Indemnitees) from and against any and all
losses, claims, demands, costs, damages, liabilities, expenses,
judgments, fines, settlements and other amounts arising out of
or incidental to the business of VOC Brazos, if: (i) the
Indemnitee acted in good faith and in a manner he, she or it
reasonably believed to be in, or not opposed to, the interests
of VOC Brazos, and, with respect to any criminal proceeding, had
no reason to believe its, his, or her conduct was unlawful; and
(ii) the Indemnitees conduct did not constitute
actual fraud, gross negligence, embezzlement, or willful and
wanton misconduct. Any indemnification shall be satisfied solely
out of property of VOC Brazos, and the general partner and the
limited partners are not subject to personal liability by reason
of the indemnification provisions. The right to indemnification
shall include the right to be paid or reimbursed by VOC Brazos
the reasonable expenses incurred by the Indemnitee who was, is
or is threatened to be made a named defendant or respondent in a
proceeding in advance of the final disposition of the proceeding
and without any determination as to the Indemnitees
ultimate entitlement to indemnification.
CONTRACTS
WITH AFFILIATES
VOC Brazos may enter into various contracts and agreements with
the general partner and with affiliates of the limited partners
provided that either (a) the transaction is on the same
terms and conditions as similar transactions in the market with
non-affiliates or (b) the holders of a majority of the
limited partner interests, knowing the material facts of the
transaction and the
VOC-23
limited partners or general partners interest, as
applicable, authorize, approve or ratify the transaction.
RIGHTS OF
THE PARTNERS
The limited partners have the right to: (1) have the books
and records of VOC Sponsor kept at its principal office and at
all reasonable times to inspect and copy any of them;
(2) have on demand true and full information of all things
affecting VOC Brazos and a formal account of the affairs of VOC
Brazos whenever circumstances render it just and reasonable;
(3) cause the dissolution and winding up of VOC Brazos by a
vote of the holders of the majority of the limited partner
interests; and (4) exercise all of the rights of a member
under the Texas LP Act. In addition, the limited partners shall
be entitled to receive quarterly and annual unaudited financial
statements of VOC Brazos, promptly after becoming available and
without need for demand, at the expense of VOC Brazos. The
limited partners and their agents and representatives, from time
to time, have the right to receive from the general partner
certain monthly, quarterly, and annual reports as have been
delivered to the limited partners to date including, but not
limited to, reports containing: (1) an estimation of the
oil and gas reserves attributable to the interest of VOC Brazos
and of the limited partner therein; (2) a projection of the
rate of production of and net income from such reserves with
respect to each such interest; (3) a calculation of the
present worth of such net income discounted at a rate or rates
designated from time to time by the limited partner; and
(4) a schedule or complete description of all assumptions,
estimates and projections made or used in the preparation of
such report, including estimated future product prices, capital
expenditures, operating expenses and taxes.
The interest of a limited partner in VOC Brazos is transferable,
but no such transfer may be made if such transfer would
(i) violate any applicable federal or state securities laws
or rules and regulations of the Securities and Exchange
Commission, any state securities commission or any other
governmental authority with jurisdiction over the transfer;
(ii) affect VOC Brazos qualification as a limited
partnership under the Texas LP Act, or would expose any limited
partner to personal liability for acts or omissions of VOC
Brazos, (iii) have the effect of separating the voting
rights from the economic rights of the interest, or
(iv) constitute an event of default under the terms of the
Partnership Agreement of VOC Brazos. VOC Brazos may, but is not
required to, recognize the assignment from the transferring
partner to the assignee on the books and records of VOC Brazos,
and may, but is not required to, recognize such assignment for
purposes of determining and making distributions, allocations,
or liquidations. No transfer of a limited partner interest of
VOC Brazos, other than a transfer to a permitted transferee
under the Partnership Agreement or upon the occurrence of
certain events may occur unless VOC Brazos right of first
refusal under the Partnership Agreement is first satisfied.
REMOVAL
OF GENERAL PARTNER
The limited partners may remove the general partner upon a vote
of the holders of a majority of the limited partner interests
(including, for this purpose, voting interests held by the
general partner), whether or not the general partner is proposed
to be removed for cause or not for cause.
AMENDMENT
OF THE PARTNERSHIP AGREEMENT
The Partnership Agreement may be amended only by an instrument
in writing duly approved by a vote of the holders of a majority
of the limited partner interests.
VOC-24
DISSOLUTION
VOC Brazos will continue as a limited partnership until
terminated under the Partnership Agreement. VOC Brazos will
dissolve upon: (1) the approval of the holders of a
majority of the limited partner interests to dissolve VOC
Brazos, provided such approval and dissolution would not
constitute an event of default under the terms of any agreement
of VOC Brazos; (2) the occurrence of an event which would
cause the dissolution of VOC Brazos under the Texas LP Act;
(3) the sole general partner resigns, is removed, withdraws
or suffers, except in the event of bankruptcy, death, divorce,
incapacity, transfer by gift, transfer upon foreclosure or other
enforcement of a security interest or lien, or termination of a
partner and one or more general partners are not admitted to VOC
Brazos within 90 days thereafter.
LIQUIDATION
AND TERMINATION
Upon dissolution of VOC Brazos, a liquidator or liquidating
committee (the Liquidator) approved by the general
partner, which such person or group may include the general
partner or any limited partner or officer, will wind up the
affairs and make final distribution. The Liquidator shall
continue to operate the properties of VOC Brazos with all of the
power and authority of the general partner necessary or
appropriate to liquidate the assets of VOC Brazos and apply the
proceeds of the liquidation as described in the Partnership
Agreement. Any assets distributed to the members upon
liquidation shall be subject to the partnership agreements then
in effect; provided, however, that if any lease is subject to an
operating agreement to which an unaffiliated third person is not
a party, such lease shall be subject to a standard form
operating agreement as shall be agreed upon by the limited
partners. Upon written request made by any limited partner, the
Liquidator shall sell VOC Brazos leases and other
properties and assets that otherwise would be distributable to
such limited partner at the best cash price available therefor
and distribute such cash (after deducting all expenses
reasonably relating to such sale) to such limited member.
VOC-25
INDEX TO
FINANCIAL STATEMENTS
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|
|
|
|
PREDECESSOR:
|
|
|
|
|
|
|
|
VOC F-2
|
|
|
|
|
VOC F-3
|
|
|
|
|
VOC F-4
|
|
|
|
|
VOC F-5
|
|
|
|
|
VOC F-6
|
|
|
|
|
VOC F-7
|
|
|
|
|
|
|
Introduction
|
|
|
VOC F-27
|
|
|
|
|
VOC F-28
|
|
|
|
|
VOC F-29
|
|
|
|
|
VOC F-30
|
|
VOC F-1
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
VOC Brazos Energy Partners, L.P.
We have audited the accompanying combined balance sheets of VOC
Brazos Energy Partners, L.P. (VOC Brazos), together
with interests in certain oil and natural gas properties of VOC
Kansas Energy Partners, LLC (KEP) under common
control with VOC Brazos (the Common Control
Properties), as of December 31, 2008 and 2009 and the
related combined statements of earnings, changes in
partners capital and cash flows for each of the three
years in the period ended December 31, 2009. When used
herein, Predecessor refers to combination of VOC
Brazos and the Common Control Properties. These combined
financial statements are the responsibility of
Predecessors management. Our responsibility is to express
an opinion on these 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. Predecessor is not required to
have, nor were we engaged to perform, an audit of its internal
control over financial reporting. Our audit included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of Predecessors internal control over
financial reporting. Accordingly, we express no such opinion. An
audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the combined 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.
In our opinion, the combined financial statements referred to
above present fairly, in all material respects, the financial
position of Predecessor as of December 31, 2008 and 2009,
and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2009, in
conformity with accounting principles generally accepted in the
United States of America.
As discussed in note A4 to the combined financial
statements, the Predecessor adopted new oil and gas reserve
estimation and disclosure requirements as of December 31,
2009.
Grant Thornton LLP
Wichita, Kansas
December 29, 2010
VOC F-2
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|
|
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|
|
December 31,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
ASSETS
|
CURRENT ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3,680,620
|
|
|
$
|
4,931,842
|
|
|
$
|
10,041,005
|
|
Accounts receivable oil and gas sales
|
|
|
722,307
|
|
|
|
1,090,371
|
|
|
|
938,871
|
|
Accounts receivable oil and gas sales
related parties, net of allowance for doubtful accounts of
$1,726,655 in 2008 and $1,007,594 in 2009 and 2010
|
|
|
2,781,714
|
|
|
|
3,622,470
|
|
|
|
3,889,717
|
|
Settlement receivable on oil swap agreements
|
|
|
513,751
|
|
|
|
|
|
|
|
31,262
|
|
Oil swap agreements
|
|
|
2,975,624
|
|
|
|
|
|
|
|
911,691
|
|
Prepaid expenses
|
|
|
70,802
|
|
|
|
68,828
|
|
|
|
127,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
10,744,818
|
|
|
|
9,713,511
|
|
|
|
15,939,746
|
|
OIL AND GAS PROPERTIES
|
|
|
108,124,590
|
|
|
|
111,171,636
|
|
|
|
118,974,942
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
17,112,290
|
|
|
|
22,098,350
|
|
|
|
26,331,798
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91,012,300
|
|
|
|
89,073,286
|
|
|
|
92,643,144
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil swap agreements
|
|
|
5,385,249
|
|
|
|
1,371,351
|
|
|
|
333,700
|
|
Deferred loan costs, net of accumulated amortization of $289,264
in 2008, $855,173 in 2009 and $1,263,354 in 2010
|
|
|
1,687,148
|
|
|
|
1,121,357
|
|
|
|
695,527
|
|
Deferred offering costs
|
|
|
|
|
|
|
|
|
|
|
14,268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,072,397
|
|
|
|
2,492,708
|
|
|
|
1,043,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
108,829,515
|
|
|
$
|
101,279,505
|
|
|
$
|
109,626,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL/COMMON CONTROL
OWNERS EQUITY
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
55,679
|
|
|
$
|
46,517
|
|
|
$
|
12,286
|
|
Related parties
|
|
|
819,583
|
|
|
|
1,285,891
|
|
|
|
1,415,526
|
|
Accrued interest
|
|
|
400,821
|
|
|
|
146,839
|
|
|
|
125,811
|
|
Settlement payable on oil swap agreements
|
|
|
|
|
|
|
106,139
|
|
|
|
35,757
|
|
Accrued ad valorem taxes
|
|
|
488,281
|
|
|
|
378,040
|
|
|
|
890,631
|
|
Other accrued liabilities
|
|
|
379,010
|
|
|
|
377,411
|
|
|
|
182,376
|
|
Current maturities of notes payable
|
|
|
1,802,902
|
|
|
|
1,531,276
|
|
|
|
267,193
|
|
Oil swap agreements
|
|
|
|
|
|
|
1,580,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
3,946,276
|
|
|
|
5,452,963
|
|
|
|
2,929,580
|
|
LONG-TERM LIABILITIES, less current maturities
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes payable
|
|
|
33,214,365
|
|
|
|
25,661,011
|
|
|
|
24,000,000
|
|
Asset retirement obligation
|
|
|
3,803,915
|
|
|
|
2,653,676
|
|
|
|
2,764,865
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37,018,280
|
|
|
|
28,314,687
|
|
|
|
26,764,865
|
|
COMMITMENTS AND CONTINGENCIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PARTNERS
CAPITAL/COMMON
CONTROL OWNERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner capital account
|
|
|
335,922
|
|
|
|
483,527
|
|
|
|
697,791
|
|
Limited partners capital account
|
|
|
42,073,523
|
|
|
|
48,246,417
|
|
|
|
57,776,184
|
|
Common control owners equity
|
|
|
17,428,336
|
|
|
|
18,991,410
|
|
|
|
20,513,302
|
|
Accumulated other comprehensive income (loss)
|
|
|
8,027,178
|
|
|
|
(209,499
|
)
|
|
|
944,663
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67,864,959
|
|
|
|
67,511,855
|
|
|
|
79,931,940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
108,829,515
|
|
|
$
|
101,279,505
|
|
|
$
|
109,626,385
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these combined statements.
VOC F-3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended December 31,
|
|
|
September 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
21,289,980
|
|
|
$
|
32,197,559
|
|
|
$
|
25,745,771
|
|
|
$
|
17,944,645
|
|
|
$
|
29,089,570
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
4,452
|
|
|
|
4,443
|
|
|
|
1,681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,289,980
|
|
|
|
32,197,559
|
|
|
|
25,750,223
|
|
|
|
17,949,088
|
|
|
|
29,091,251
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
6,586,226
|
|
|
|
7,667,332
|
|
|
|
6,787,857
|
|
|
|
5,053,546
|
|
|
|
5,228,613
|
|
Production and property taxes
|
|
|
1,874,237
|
|
|
|
2,531,660
|
|
|
|
1,646,052
|
|
|
|
1,257,919
|
|
|
|
1,918,959
|
|
Depreciation, depletion, amortization and accretion
|
|
|
2,258,922
|
|
|
|
5,780,829
|
|
|
|
5,210,212
|
|
|
|
4,325,407
|
|
|
|
4,354,677
|
|
Interest expense
|
|
|
363,230
|
|
|
|
1,382,725
|
|
|
|
1,500,647
|
|
|
|
1,168,229
|
|
|
|
920,104
|
|
Bad debt expense (recovery)
|
|
|
|
|
|
|
1,726,655
|
|
|
|
(719,061
|
)
|
|
|
(719,061
|
)
|
|
|
|
|
General and administrative
|
|
|
120,518
|
|
|
|
269,139
|
|
|
|
463,295
|
|
|
|
242,965
|
|
|
|
111,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
11,203,133
|
|
|
|
19,358,340
|
|
|
|
14,889,002
|
|
|
|
11,329,005
|
|
|
|
12,533,929
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
$
|
10,086,847
|
|
|
$
|
12,839,219
|
|
|
$
|
10,861,221
|
|
|
$
|
6,620,083
|
|
|
$
|
16,557,322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these combined statements.
VOC F-4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redeemed
|
|
|
New
|
|
|
Common
|
|
|
Accumulated
|
|
|
|
|
|
|
General
|
|
|
Limited
|
|
|
Limited
|
|
|
Control
|
|
|
Other
|
|
|
|
|
|
|
Partner
|
|
|
Partner
|
|
|
Partners
|
|
|
Owners
|
|
|
Comprehensive
|
|
|
|
|
|
|
Capital
|
|
|
Capital
|
|
|
Capital
|
|
|
Equity
|
|
|
Income (Loss)
|
|
|
Total
|
|
|
Balance at January 1, 2007
|
|
$
|
259,713
|
|
|
$
|
25,711,560
|
|
|
$
|
|
|
|
$
|
11,727,423
|
|
|
$
|
(1,618,966
|
)
|
|
$
|
36,079,730
|
|
Partners distributions
|
|
|
(58,820
|
)
|
|
|
(5,823,180
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,882,000
|
)
|
Common control owners contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,735,400
|
|
|
|
|
|
|
|
1,735,400
|
|
Common control owners distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,542,185
|
)
|
|
|
|
|
|
|
(5,542,185
|
)
|
Comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings for the year
|
|
|
68,315
|
|
|
|
6,763,165
|
|
|
|
|
|
|
|
3,255,367
|
|
|
|
|
|
|
|
10,086,847
|
|
Reclassification adjustment for realized losses on swap
transactions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,765,858
|
|
|
|
3,765,858
|
|
Change in fair value of swap agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,140,303
|
)
|
|
|
(12,140,303
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,712,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
269,208
|
|
|
|
26,651,545
|
|
|
|
|
|
|
|
11,176,005
|
|
|
|
(9,993,411
|
)
|
|
|
28,103,347
|
|
Partners capital contributions
|
|
|
|
|
|
|
|
|
|
|
40,000,000
|
|
|
|
|
|
|
|
|
|
|
|
40,000,000
|
|
Partners distributions
|
|
|
(33,350
|
)
|
|
|
(73,301,650
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(73,335,000
|
)
|
Common control owners contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,128,500
|
|
|
|
|
|
|
|
5,128,500
|
|
Common control owners distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,169,277
|
)
|
|
|
|
|
|
|
(5,169,277
|
)
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings for the year
|
|
|
100,064
|
|
|
|
4,372,524
|
|
|
|
2,073,523
|
|
|
|
6,293,108
|
|
|
|
|
|
|
|
12,839,219
|
|
Reclassification adjustment for realized losses on swap
transactions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,939,518
|
|
|
|
5,939,518
|
|
Change in fair value of swap agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,081,071
|
|
|
|
12,081,071
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,859,808
|
|
Step-up in
basis of leasehold costs and lease equipment equal to the
limited partners liquidating distribution in excess of the
partners capital account
|
|
|
|
|
|
|
42,277,581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,277,581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
335,922
|
|
|
|
|
|
|
|
42,073,523
|
|
|
|
17,428,336
|
|
|
|
8,027,178
|
|
|
|
67,864,959
|
|
Common control owners contributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
400,000
|
|
|
|
|
|
|
|
400,000
|
|
Common control owners distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,377,648
|
)
|
|
|
|
|
|
|
(3,377,648
|
)
|
Comprehensive income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings for the year
|
|
|
147,605
|
|
|
|
|
|
|
|
6,172,894
|
|
|
|
4,540,722
|
|
|
|
|
|
|
|
10,861,221
|
|
Reclassification adjustment for realized gains on swap
transactions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,347,010
|
)
|
|
|
(1,347,010
|
)
|
Change in fair value of swap agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,889,667
|
)
|
|
|
(6,889,667
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,624,544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
483,527
|
|
|
|
|
|
|
|
48,246,417
|
|
|
|
18,991,410
|
|
|
|
(209,499
|
)
|
|
|
67,511,855
|
|
Partners distributions (unaudited)
|
|
|
(6,500
|
)
|
|
|
|
|
|
|
(318,500
|
)
|
|
|
|
|
|
|
|
|
|
|
(325,000
|
)
|
Common control owners distributions (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,966,399
|
)
|
|
|
|
|
|
|
(4,966,399
|
)
|
Comprehensive income (unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings for the period
|
|
|
220,764
|
|
|
|
|
|
|
|
9,848,267
|
|
|
|
6,488,291
|
|
|
|
|
|
|
|
16,557,322
|
|
Reclassification adjustment for realized losses on swap
transactions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
451,354
|
|
|
|
451,354
|
|
Change in fair value of swap agreements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
702,808
|
|
|
|
702,808
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,711,484
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2010 (unaudited)
|
|
$
|
697,791
|
|
|
$
|
|
|
|
$
|
57,776,184
|
|
|
$
|
20,513,302
|
|
|
$
|
944,663
|
|
|
$
|
79,931,940
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these combined statements.
VOC F-5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended December 31,
|
|
|
September 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
$
|
10,086,847
|
|
|
$
|
12,839,219
|
|
|
$
|
10,861,221
|
|
|
$
|
6,620,083
|
|
|
$
|
16,557,322
|
|
Adjustments to reconcile net earnings to net cash provided by
operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and accretion
|
|
|
2,258,922
|
|
|
|
5,780,829
|
|
|
|
5,210,212
|
|
|
|
4,325,407
|
|
|
|
4,354,677
|
|
Amortization of deferred loan costs
|
|
|
3,806
|
|
|
|
285,154
|
|
|
|
565,909
|
|
|
|
424,431
|
|
|
|
425,830
|
|
Bad debt expense
|
|
|
|
|
|
|
1,726,655
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized derivative (gain) loss
|
|
|
3,250,583
|
|
|
|
(3,581,995
|
)
|
|
|
333,695
|
|
|
|
333,695
|
|
|
|
(300,728
|
)
|
Settlements of asset retirement obligation
|
|
|
(1,737
|
)
|
|
|
(25,143
|
)
|
|
|
(27,149
|
)
|
|
|
(27,149
|
)
|
|
|
(235,053
|
)
|
Change in operating assets and liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(1,304,197
|
)
|
|
|
(1,306,761
|
)
|
|
|
(1,208,820
|
)
|
|
|
(1,526,664
|
)
|
|
|
(115,747
|
)
|
Settlement receivable on swap agreements
|
|
|
46,170
|
|
|
|
(513,751
|
)
|
|
|
513,751
|
|
|
|
513,751
|
|
|
|
(31,262
|
)
|
Prepaid expenses
|
|
|
2,211
|
|
|
|
5,432
|
|
|
|
1,974
|
|
|
|
(745,603
|
)
|
|
|
(58,372
|
)
|
Accounts payable
|
|
|
180,332
|
|
|
|
(132,958
|
)
|
|
|
(109,862
|
)
|
|
|
9,873
|
|
|
|
69,998
|
|
Accrued liabilities
|
|
|
60,491
|
|
|
|
228,828
|
|
|
|
(205,242
|
)
|
|
|
179,877
|
|
|
|
512,591
|
|
Accrued interest payable
|
|
|
(3,421
|
)
|
|
|
382,102
|
|
|
|
(253,982
|
)
|
|
|
(255,516
|
)
|
|
|
(21,028
|
)
|
Settlement payable on swap agreements
|
|
|
499,557
|
|
|
|
(713,268
|
)
|
|
|
106,139
|
|
|
|
16,965
|
|
|
|
(70,382
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
15,079,564
|
|
|
|
14,974,343
|
|
|
|
15,787,846
|
|
|
|
9,869,150
|
|
|
|
21,087,846
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of oil and gas properties and equipment
|
|
|
(3,452,245
|
)
|
|
|
(6,675,201
|
)
|
|
|
(2,151,315
|
)
|
|
|
(1,057,571
|
)
|
|
|
(2,298,690
|
)
|
Well development cost
|
|
|
(1,372,221
|
)
|
|
|
(1,245,986
|
)
|
|
|
(1,582,563
|
)
|
|
|
(782,600
|
)
|
|
|
(5,449,232
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(4,824,466
|
)
|
|
|
(7,921,187
|
)
|
|
|
(3,733,878
|
)
|
|
|
(1,840,171
|
)
|
|
|
(7,747,922
|
)
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of notes payable
|
|
|
750,000
|
|
|
|
32,622,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments on notes payable
|
|
|
(926,365
|
)
|
|
|
(1,293,757
|
)
|
|
|
(7,824,980
|
)
|
|
|
(7,444,767
|
)
|
|
|
(2,925,094
|
)
|
Payment of deferred loan costs
|
|
|
(12,667
|
)
|
|
|
(1,958,881
|
)
|
|
|
(118
|
)
|
|
|
(118
|
)
|
|
|
|
|
Payment of deferred offering costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,268
|
)
|
Partners contributions
|
|
|
|
|
|
|
40,000,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners distributions
|
|
|
(5,882,000
|
)
|
|
|
(73,335,000
|
)
|
|
|
|
|
|
|
|
|
|
|
(325,000
|
)
|
Common control owners contributions
|
|
|
1,735,400
|
|
|
|
5,128,500
|
|
|
|
400,000
|
|
|
|
400,000
|
|
|
|
|
|
Common control owners distributions
|
|
|
(5,542,185
|
)
|
|
|
(5,169,277
|
)
|
|
|
(3,377,648
|
)
|
|
|
(2,751,138
|
)
|
|
|
(4,966,399
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in financing activities
|
|
|
(9,877,817
|
)
|
|
|
(4,005,515
|
)
|
|
|
(10,802,746
|
)
|
|
|
(9,796,023
|
)
|
|
|
(8,230,761
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
377,281
|
|
|
|
3,047,641
|
|
|
|
1,251,222
|
|
|
|
(1,767,044
|
)
|
|
|
5,109,163
|
|
Cash and cash equivalents, beginning of period
|
|
|
255,698
|
|
|
|
632,979
|
|
|
|
3,680,620
|
|
|
|
3,680,620
|
|
|
|
4,931,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
632,979
|
|
|
$
|
3,680,620
|
|
|
$
|
4,931,842
|
|
|
$
|
1,913,576
|
|
|
$
|
10,041,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the period for interest
|
|
$
|
362,845
|
|
|
$
|
715,469
|
|
|
$
|
1,188,720
|
|
|
$
|
999,313
|
|
|
$
|
515,302
|
|
Noncash investing and financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement costs and obligation recorded upon drilling of
new oil and gas wells
|
|
$
|
83,668
|
|
|
$
|
238,516
|
|
|
$
|
77,632
|
|
|
$
|
9,038
|
|
|
$
|
29,978
|
|
Increase (decrease) in asset retirement cost and obligation due
to changes in timing and estimated cash flows
|
|
$
|
145,120
|
|
|
$
|
1,067,315
|
|
|
$
|
(1,331,472
|
)
|
|
$
|
|
|
|
$
|
|
|
Purchases of oil and gas properties and equipment and well
development costs included in accounts payable at year end
|
|
$
|
520,180
|
|
|
$
|
227,927
|
|
|
$
|
794,935
|
|
|
$
|
138,400
|
|
|
$
|
820,341
|
|
Step-up in
basis of oil and gas properties as a result of redemption of
limited partners interest
|
|
$
|
|
|
|
$
|
42,277,581
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
The accompanying notes are an
integral part of these combined statements.
VOC F-6
Predecessor
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
NOTE A
SUMMARY OF ACCOUNTING POLICIES
A summary of the significant accounting policies consistently
applied in the preparation of the accompanying combined
financial statements follows.
1. Principles
of combination
In connection with the closing of the initial public offering of
trust units of VOC Energy Trust, pursuant to that certain
Contribution and Exchange Agreement dated August 30, 2010,
VOC Brazos Energy Partners, L.P. (VOC Brazos) will
acquire all of the membership interests in VOC Kansas Energy
Partners, LLC (KEP) in exchange for newly issued
limited partner interests in VOC Brazos, resulting in KEP
becoming a wholly-owned subsidiary of VOC Brazos. As certain
working interests owned by KEP (the Common Control
Properties) are deemed to be under common control with VOC
Brazos, accounting rules specify that VOC Brazos and the Common
Control Properties be combined from the earliest date they came
under common control. Per accounting guidance under FASB ASC 805
regarding business combinations, those assets and liabilities of
the Common Control Properties are to be recorded at their
historical costs in the records of KEP while those not under
common control are to be recorded at their fair values on the
date of combination.
Accordingly, these combined financial statements include the
accounts of VOC Brazos and certain oil and gas properties and
other related assets and liabilities of the Common Control
Properties for all periods presented. Together, these entities
are referred to as Predecessor.
2. History
and business activity
VOC Brazos was organized during 2003 between Vess Texas
Partners, LLC, the general partner and TIFD III-X, LLC, the
limited partner, to engage in acquisition, exploration,
development and production of oil and gas. VOC Brazos began
operations August 1, 2003 when the partners contributed
working interests in certain oil and gas properties in Texas
into the partnership as a contribution of capital.
The properties had been held in a similar partnership in which
TIFD III-X, LLC held a 99% limited partnership interest. Because
of the continuity of ownership, the properties were recorded on
the partnership books at the lesser of historical cost or fair
value. The partnership agreement of VOC Brazos provided
that 1% of the contributed properties were deemed to have been
contributed by the general partner.
Through June 27, 2008, revenues and costs of
VOC Brazos were generally allocated 99% to the limited
partner and 1% to the general partner.
On June 27, 2008, VOC Brazos entered into a master
transaction agreement to redeem all of TIFD III-X, LLCs
limited partner interest in the partnership for $70 million
which was obtained by issuance of a $30 million note
payable (See Note C) and receipt of $40 million
in capital contributions from two new limited partners, VAP-III,
LLC and Vess Texas Acquisition Group, LLC. After this
redemption, Vess Texas Partners, LLC has a 2% general partner
interest, VAP-III,
VOC F-7
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
LLC has a 56.53% limited partner interest and Vess Texas
Acquisition Group, LLC has a 41.47% limited partner interest.
The excess of the $70 million liquidating distribution over
TIFD III-X, LLCs capital account or $42,277,581 was
recorded as a
step-up in
basis to producing leaseholds and lease equipment.
The Common Control Properties consist of working interests in
certain oil and gas properties located in Kansas. Some of these
properties have been owned since 1979. The related assets and
liabilities include oil and gas receivables, oil swap agreements
and the related settlements receivable or payable, capitalized
loan fees, joint interest billing payables, ad valorem tax
accruals, asset retirement obligations and long-term debt
associated with the acquisition of certain oil and gas
properties. These combined financial statements do not reflect
any administrative overhead costs for the Common Control
Properties as prior to the KEP consolidation each of the 24
owners conducted its own accounting for its respective
properties and did not allocate administrative overhead costs to
the properties.
3. Interim
financial statements
The financial information as of September 30, 2010 and for
the nine months ended September 30, 2009 and 2010 is
unaudited. In the opinion of management, such information
contains all adjustments, consisting only of normal recurring
accruals, considered necessary for a fair presentation of the
results of the interim periods. The results of operations for
the nine month period ended September 30, 2010 are not
necessarily indicative of the results of operations that will be
realized for the year ending December 31, 2010.
4. Oil
and gas properties
Predecessor follows the successful efforts method of accounting
for oil and gas property acquisition, exploration, development
and production activities.
Oil and gas property acquisition costs, exploration well costs
and development well costs are capitalized as incurred. Net
capitalized costs of unproven property and exploration well
costs are reclassified as proved property and well costs when
related proved reserves are found. If an exploration well is
unsuccessful in finding proved reserves, the capitalized well
costs are charged to exploration expense. Other exploration
costs, including geological and geophysical costs, and the costs
of carrying unproved property are charged to exploration expense
as incurred.
Producing leasehold costs are amortized by property using the
unit-of-production
method based upon total estimated proved reserves. Capitalized
exploration well costs and development costs and lease equipment
(plus estimated future equipment dismantlement, surface
restoration, and property abandonment costs, net of equipment
salvage values) are amortized by property using the
unit-of-production
method based on estimated proved developed reserves.
Predecessor reviews its long-lived assets, including its oil and
gas properties, for impairment whenever events or circumstances
indicate that the carrying amount of an asset may not be
recoverable. Predecessor determines whether an impairment has
occurred by estimating the undiscounted expected future net cash
flows of its oil and gas properties at a field level and
VOC F-8
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
compares such cash flows to the carrying amount of the oil and
gas properties to determine if the carrying amount is
recoverable. For those oil and gas properties for which the
carrying amount exceeds the undiscounted estimated future cash
flows, an impairment is determined to exist. The carrying amount
of such properties is adjusted to their estimated net fair value
based on relevant market information or discounted cash flows.
In December 2009, Predecessor adopted new accounting guidance
for oil and gas reserve estimation and disclosure requirements.
This guidance revised the definition of proved oil and gas
reserves to require that the average,
first-day-of-the-month
price during the
12-month
period before the end of the year, rather than the year-end
price, be used when estimating whether reserve quantities are
economical to produce. The guidance also allows for the use of
reliable technology to estimate proved oil and gas reserves if
those technologies have been demonstrated to result in reliable
conclusions about reserve volumes.
Costs of retired, sold or abandoned properties that constitute a
part of an amortization base are charged or credited, net of
proceeds, to the accumulated depreciation, depletion and
amortization reserve. Gains or losses from the disposal of other
properties are recognized currently. Expenditures for
maintenance, repairs and minor renewals necessary to maintain
properties in operating condition are expensed as incurred.
Major replacements and renewals are capitalized. All properties
are stated at cost.
5. Revenue
recognition
Revenues from the sale of oil and gas production are recognized
as oil and gas is produced and sold.
6. Derivatives
Predecessor uses swap agreements to mitigate the effects of
fluctuations in the prices of crude oil. These agreements
involve the exchange of amounts based on a fluctuating oil price
for amounts based on a fixed oil price over the life of the
agreement, without an exchange of the notional amount upon which
the payments are based. The differential paid or received is
recognized as an adjustment of oil and gas revenue.
Predecessors derivatives, consisting entirely of oil swap
agreements, for which substantially all qualify as cash flow
hedges. As such, all of Predecessors swap agreements are
recorded on the balance sheet at fair value. For all derivatives
designated as cash flow hedges, the effective portion of the
unrealized gain or loss on the derivative instrument is recorded
as a component of accumulated other comprehensive income (loss)
and reclassified into earnings as the underlying hedged item
effects earnings. The ineffective portion of the derivative as
well as those not qualifying as cash flow hedges are recorded as
an adjustment to revenue in the statements of earnings.
VOC F-9
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
7. Accounts
receivable
Predecessors trade accounts receivable from the properties
contributed at the inception of VOC Brazos are collected by a
revenue intermediary from an unrelated purchaser. The revenue
intermediary then disburses the revenue based upon the revenue
deck that they maintain. Predecessors trade accounts
receivable for the properties acquired subsequent to the
inception of VOC Brazos are remitted directly from the
purchaser. State law requires that receipts for the initial
production of oil or gas sales must be paid on or before
120 days after the end of the month of the first sale of
production from the well. Thereafter, state law requires that
crude oil sales are paid within 60 days following the
related production and receipts for natural gas sales are paid
within 90 days following the related production. Except for
the trade receivable from the former revenue intermediary/crude
oil purchaser (see Note E), Predecessor considers the trade
receivables to be fully collectible and has historically not
experienced any collection issues. If additional amounts become
uncollectible, they will be charged to operations when that
determination is made.
8. Cash
equivalents
For purposes of the statement of cash flows, Predecessor
considers all highly liquid investments purchased with an
original maturity of three months or less to be cash
equivalents. There were no cash equivalents at December 31,
2008 and 2009.
9. Deferred
loan costs
Deferred loan costs are being amortized over the term of the
related loan and are included in interest expense.
10. Deferred
offering costs
Deferred offering costs consist of legal, accounting,
engineering and other costs associated with the proposed sale of
a term net profits interest in the oil and natural gas
properties of Predecessor. If the sale is successful, these
costs will be netted against the offering proceeds. If the sale
is unsuccessful, these costs will be reclassified to operations.
11. Use
of estimates
In preparing financial statements in conformity with accounting
principles generally accepted in the United States of America
(U.S. GAAP), management is required to make
estimates and assumptions that affect the reported amounts of
assets and liabilities, the disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amount of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Significant estimates affecting these financial statements
include estimates for quantities of proved oil and gas reserves,
asset retirement obligations and allowance for doubtful accounts
and are subject to change.
VOC F-10
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
12. Income
taxes
Federal income taxes are the liability of the individual
partners/owners; accordingly, the financial statements do not
include any provision for federal income taxes. The Texas
franchise tax is based on gross margin as defined by Texas law,
is paid by Predecessor and is recorded as a general and
administrative expense. Predecessor adopted new accounting
guidance for uncertain tax positions in 2007. This adoption had
no impact on the 2007 financial statements.
13. Asset
retirement obligations
Accounting guidance requires that the fair value of a liability
for an asset retirement obligation be recognized in the period
in which the liability is incurred. The liability is measured at
discounted fair value and is adjusted to its present value in
subsequent periods as accretion expense is recorded. Such
accretion expense is included in depreciation, depletion,
amortization and accretion in the accompanying statements of
earnings. The corresponding asset retirement costs are
capitalized as part of the carrying amount of the related
long-lived asset and amortized over the assets useful
life. If the fair value of the estimated retirement obligation
changes, an adjustment is recorded for both the asset retirement
obligation and the asset retirement cost. The Predecessors
asset retirement obligations are primarily associated with the
plugging and abandoning of oil and gas properties.
The estimated plug and abandon dates change routinely based upon
additional engineering data and changes in the price of oil
impacting the date when the well is no longer economically
feasible to operate. The asset retirement obligation is measured
on an annual basis based upon the then current plug and abandon
dates of the wells using the original measurement date rates.
Asset retirement obligations on new wells drilled are calculated
on their initial measurement date based upon the then current
interest rate environment.
14. Recently
issued accounting standards
In January 2010, the FASB issued ASU
2010-04,
Accounting for Various Topics Technical
Corrections to SEC Paragraphs. ASU
2010-04
makes technical corrections to existing SEC guidance, including
the following topics: accounting for subsequent investments,
termination of an interest rate swap, issuance of financial
statements subsequent events, use of residential
method to value acquired assets other than goodwill, adjustments
in assets and liabilities for holding gains and losses, and
selections of discount rate used for measuring defined benefit
obligation. The adoption of ASU
2010-04 did
not have a material impact on our financial statements.
In January 2010, the FASB issued ASU
2010-06,
Improving Disclosures about Fair Value Measurements
(ASU
2010-06),
which provides amendments to ASC topic Fair Value
Measurements and Disclosures. This will provide more
robust disclosures about (i) the different classes of
assets and liabilities measured at fair value, (ii) the
valuation techniques and inputs used, (iii) the activity in
Level 3 fair value measurements, and (iv) the
transfers between Levels 1, 2 and 3. ASU
2010-06 is
effective for fiscal years and interim periods beginning after
December 15, 2009. The adoption did not have a material
impact to our financial statements.
VOC F-11
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
In February 2010, the FASB issued ASU
2010-09 (ASU
2010-09),
Subsequent Events (Topic 855). The amendments
remove the requirements for an SEC filer to disclose a date, in
both issued and revised financial statements, through which
subsequent events have been reviewed. Revised financial
statements include financial statements revised as a result of
either correction of an error or retrospective application of
U.S. GAAP. ASU
2010-09 is
effective for interim or annual financial periods ending after
June 15, 2010. Adoption did not have a material effect on
our financial position, results of operations or cash flows.
In April 2010, the FASB issued ASU
2010-14,
Accounting for Extractive Activities
Oil & Gas. ASU
2010-14
amends
paragraph 932-10-S99-1
due to SEC Release
No. 33-8995,
Modernization of Oil and Gas Reporting. The
amendments to the guidance on oil and gas accounting are
effective August 31, 2010, and did not have a significant
impact on Predecessors financial position.
On August 2, 2010, the FASB issued ASU
2010-21,
Accounting for Technical Amendments to Various SEC Rules
and Schedules Amendments to SEC
Paragraphs Pursuant to Release
No. 33-9026:
Technical Amendments to Rules, Forms, Schedules and Codification
of Financial Reporting Policies. The ASU reflects changes
made by the SEC in Final Rulemaking
Release No. 33-9026,
which was issued in April 2009 and amended SEC requirements in
Regulation S-X
and
Regulation S-K
and made changes to financial reporting requirements in response
to the FASBs issuance of SFAS No. 141(R),
Business Combinations (FASB ASC 805), and
SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements an amendment of
ARB No. 51 ( FASB ASC 810). Adoption of ASU
2010-21 did
not have a material impact on Predecessors financial
statements.
NOTE B
OIL AND GAS PROPERTIES
Oil and gas properties are carried at cost and consist of the
following at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
Producing leaseholds
|
|
$
|
72,833,236
|
|
|
$
|
72,230,517
|
|
|
$
|
72,176,496
|
|
Lease equipment
|
|
|
22,125,646
|
|
|
|
23,820,846
|
|
|
|
26,039,732
|
|
Well development costs
|
|
|
13,165,708
|
|
|
|
15,120,273
|
|
|
|
20,758,714
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
108,124,590
|
|
|
|
111,171,636
|
|
|
|
118,974,942
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
17,112,290
|
|
|
|
22,098,350
|
|
|
|
26,331,798
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties
|
|
$
|
91,012,300
|
|
|
$
|
89,073,286
|
|
|
$
|
92,643,144
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
VOC F-12
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
Predecessors oil and gas activities are conducted entirely
in the United States. Costs incurred in oil and gas producing
activities for the periods indicated are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
Property acquisition costs
|
|
$
|
3,535,913
|
|
|
$
|
6,913,717
|
|
|
$
|
2,228,947
|
|
|
$
|
1,066,609
|
|
|
$
|
2,328,668
|
|
Development costs
|
|
|
1,372,221
|
|
|
|
1,245,986
|
|
|
|
1,582,563
|
|
|
|
782,600
|
|
|
|
5,449,232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,908,134
|
|
|
$
|
8,159,703
|
|
|
$
|
3,811,510
|
|
|
$
|
1,849,209
|
|
|
$
|
7,777,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The results of operations for oil and gas producing activities,
excluding corporate overhead and interest costs for the years
ended December 31 and for the nine months ended September 30 are
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
Revenues from oil and gas sales
|
|
$
|
21,289,980
|
|
|
$
|
32,197,559
|
|
|
$
|
25,745,771
|
|
|
$
|
17,944,645
|
|
|
$
|
29,089,570
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
6,586,226
|
|
|
|
7,667,332
|
|
|
|
6,787,857
|
|
|
|
5,053,546
|
|
|
|
5,228,613
|
|
Production and property taxes
|
|
|
1,874,237
|
|
|
|
2,531,660
|
|
|
|
1,646,052
|
|
|
|
1,257,919
|
|
|
|
1,918,959
|
|
Depreciation, depletion and amortization
|
|
|
2,258,922
|
|
|
|
5,780,829
|
|
|
|
5,210,212
|
|
|
|
4,325,407
|
|
|
|
4,354,677
|
|
Bad debt expense (recovery)
|
|
|
|
|
|
|
1,726,655
|
|
|
|
(719,061
|
)
|
|
|
(719,061
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from oil and gas operations
|
|
$
|
10,570,595
|
|
|
$
|
14,491,083
|
|
|
$
|
12,820,711
|
|
|
$
|
8,026,834
|
|
|
$
|
17,587,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses include those costs incurred to operate
and maintain productive wells and related equipment and include
costs such as labor, repairs and maintenance, materials,
supplies, fuel consumed and insurance.
Depreciation, depletion and amortization include costs
associated with capital acquisitions and development costs.
VOC F-13
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
NOTE C
NOTES PAYABLE
Notes payable consist of the following at:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
Credit facility see details below
|
|
$
|
30,000,000
|
|
|
$
|
24,000,000
|
|
|
$
|
24,000,000
|
|
Note payable to bank in monthly installments of $25,443
including interest at prime (prime was 4.00%, 3.25% and 3.25% at
December 31, 2008 and 2009 and September 30, 2010,
respectively), with final payment due in May 2013,
collateralized by mortgages on oil and gas properties and
guaranteed by two members of the Common Control Properties. Note
was subsequently paid in full in November 2010
|
|
|
1,170,212
|
|
|
|
876,964
|
|
|
|
267,193
|
|
Note payable to bank in monthly installments of $23,000 ($50,000
at December 31, 2008) including interest at prime
(with a floor of 4.50% which was the effective interest rate at
December 31, 2008 and 2009), with final payment due in July
2011, collateralized by mortgages on oil and gas properties and
subsequently paid in full in August 2010
|
|
|
1,373,063
|
|
|
|
831,563
|
|
|
|
|
|
Note payable to bank in monthly installments of $89,329
including interest at prime (with a floor of 4.00% which was the
effective interest rate at December 31, 2008 and 2009 and
September 30, 2010, with final payment due August 2011,
collateralized by mortgages on oil and gas properties and
subsequently paid in full in August 2010
|
|
|
2,473,992
|
|
|
|
1,483,760
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35,017,267
|
|
|
|
27,192,287
|
|
|
|
24,267,193
|
|
Less current maturities
|
|
|
1,802,902
|
|
|
|
1,531,276
|
|
|
|
267,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
33,214,365
|
|
|
$
|
25,661,011
|
|
|
$
|
24,000,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit
facility
On June 27, 2008, in connection with the redemption and
buy-out of the 99% limited partner, TIFD III-X, LLC, VOC Brazos
entered into a credit agreement with a bank with a maximum
commitment for Borrowing Base, Letters of Credit and Swing Line
Loans in the amount of $100,000,000. The Borrowing Base
Notes interest rate is adjusted periodically based on the
interest rate base (either Eurodollar Rate of one, two, three or
six month periods or the banks base rate) plus an
applicable margin based on a percentage of borrowing base usage.
The notes effective rate at December 31, 2008 and
2009 and September 30, 2010 was 5.15375%, 2.37875% and
2.19438% respectively. Interest is paid no less than quarterly
depending on the interest rate
VOC F-14
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
base selected. The note is collateralized by all assets of
Predecessor and matures on June 27, 2013. Below are further
details of Predecessors credit agreement with the bank.
Borrowing
Base loans:
Predecessors initial and current borrowing base is
$37 million and thereafter is determined periodically by
the lender. Predecessor pays a fee of 0.25% to 0.50% on the
unused portion of the borrowing base depending on the portion of
the borrowing base utilized by Predecessor.
Letters
of Credit:
The credit agreement with the bank provides for the issuance of
letters of credit. When the lender issues a letter of credit,
initial fees are charged and interest will be due based on the
Eurodollar rate plus an applicable margin of 1.50% to 2.25%
depending on the amount of Predecessors borrowing base
currently being used. At December 31, 2008 and 2009 and
September 30, 2010, Predecessor did not have any
outstanding letters of credit with the lender.
Swing
Line Loan:
Predecessor has a revolving credit facility. This revolving
credit facility is completely discretionary by the lender. The
interest rate for swing line loans is based on the Banks
base rate. At December 31, 2008 and 2009 and
September 30, 2010, Predecessor did not have an outstanding
balance on the Swing Line Loan.
Predecessor is subject to certain financial covenants associated
with the borrowings including current ratio, interest coverage
ratio and maximum leverage ratio requirements. In addition,
Predecessor was required to enter into swap agreements to cover
at least 75% of the estimated annual production through 2011.
Predecessor is in compliance with the required debt covenants at
December 31, 2009 and September 30, 2010.
The aggregate scheduled maturities of debt at December 31,
2009 are as follows
|
|
|
|
|
2010
|
|
$
|
1,531,276
|
|
2011
|
|
|
1,330,221
|
|
2012
|
|
|
298,880
|
|
2013
|
|
|
24,031,910
|
|
|
|
|
|
|
|
|
$
|
27,192,287
|
|
|
|
|
|
|
NOTE D
FINANCIAL INSTRUMENTS
The Predecessor uses swap agreements to reduce the effects of
fluctuations in crude oil prices. At December 31, 2008 and
2009, Predecessors hedging activities included swap
agreements maturing through the year 2011. Under these
arrangements, Predecessor will effectively receive fixed prices
for the oil production hedged. The price source for the
commodity type hedge is the New York Mercantile Exchange for the
monthly activity. The agreements covered 237,552 barrels,
279,603 barrels and 213,933 barrels of crude oil
production in the years
VOC F-15
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
ended December 31, 2007, 2008 and 2009, respectively.
Predecessor produced 386,879, 389,268 and 407,414 barrels
of crude oil in 2007, 2008 and 2009, respectively (unaudited).
Predecessor had agreements covering 161,520 barrels and
155,893 barrels of crude oil production in the nine months
ended September 30, 2009 and 2010, respectively
(unaudited). Predecessor produced 298,192 barrels and
374,329 barrels of crude oil in the nine months ended
September 30, 2009 and 2010, respectively (unaudited).
Gains and losses on the hedging transactions are recognized when
the hedged production is sold. Net expense recorded by
Predecessor for swap agreements was $3,996,252 and $8,118,212
for the years ended December 31, 2007 and 2008,
respectively and net revenue recorded by Predecessor for swap
agreements was $1,477,248 for the year ended December 31,
2009. Such amounts have been reflected as an adjustment to oil
and gas sales in the statements of earnings. Predecessor
recorded net revenue for swap agreements of $1,880,305 for the
nine months ended September 30, 2009 and net expense for
swap agreements of $451,354 for the nine months ended
September 30, 2010 (unaudited). In addition, Predecessor
has recorded income of $300,728 for the nine months ended
September 30, 2010 (unaudited) which represents the
ineffective portion of the unrealized gain on the hedge at
September 30, 2010. These amounts have also been reflected
as an adjustment to oil and gas sales in the statements of
earnings.
For those oil swap agreements that do not qualify as cash flow
hedges, Predecessor has also recorded the changes to fair value
as adjustments to oil and gas sales in the statement of earnings
as an expense of $3,248,300 for the year ended December 31,
2007 and income of $333,695 for the year ended December 31,
2008.
The notional volume and fair market value of outstanding swap
agreements at December 31, 2008 and 2009 and
September 30, 2010 (unaudited) are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
Year
|
|
|
Notional Volume
|
|
Fixed Price
|
|
|
Fair Value
|
|
|
|
|
|
|
|
2009
|
(A)
|
|
28,800 bbls
|
|
$
|
66.32
|
|
|
$
|
333,695
|
|
|
|
|
|
|
2009
|
|
|
185,133 bbls
|
|
|
68.85
|
|
|
|
2,641,929
|
|
|
|
|
|
|
2010
|
|
|
174,571 bbls
|
|
|
73.06
|
|
|
|
1,535,360
|
|
|
|
|
|
|
2011
|
|
|
159,894 bbls
|
|
|
94.90
|
|
|
|
3,849,889
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
8,360,873
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
Year
|
|
|
Notional Volume
|
|
Fixed Price
|
|
|
Fair Value
|
|
|
|
|
|
|
|
2010
|
|
|
174,571 bbls
|
|
|
73.06
|
|
|
$
|
(1,580,850
|
)
|
|
|
|
|
|
2011
|
|
|
159,894 bbls
|
|
|
94.90
|
|
|
|
1,371,351
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(209,499
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
VOC F-16
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
Year
|
|
|
Notional Volume
|
|
Fixed Price
|
|
|
Fair Value
|
|
|
|
|
|
|
|
2010
|
|
|
42,678 bbls
|
|
|
73.06
|
|
|
$
|
(345,524
|
)
|
|
|
|
|
|
2011
|
|
|
159,894 bbls
|
|
|
94.90
|
|
|
|
1,590,915
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,245,391
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(A) |
|
Does not qualify as cash flow hedge. |
Predecessors swap agreements expose it to market and
credit risks that may, at times, be concentrated with certain
counterparties or groups of counterparties. At December 31,
2009, Predecessors financial instruments were with one
major financial institution whose credit worthiness is subject
to continuing review, however, full performance is anticipated.
The estimated amount of unrealized loss relating to hedge
agreements at December 31, 2009 expected to be reclassified
into earnings in the next 12 months is $1,587,315. See
Note A6 for more discussion on derivatives.
NOTE E
RELATED PARTIES
Vess Texas Partners, LLC, the general partner of Predecessor,
has common ownership with Vess Oil Corporation. Vess Oil
Corporation serves as the primary operator of the oil and gas
wells of the Partnership. In addition, the primary owner of the
primary operator has a minority investment interest in the
parent of the revenue intermediary prior to July 22, 2008.
As a result of the bankruptcy discussed below, Vess Oil
Corporation became the new revenue intermediary on July 22,
2008.
VOC F-17
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
Below is a summary of transactions that occurred between
Predecessor, its general partner, operator and revenue
intermediary:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
With operator/new revenue intermediary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense incurred
|
|
$
|
5,596,992
|
|
|
$
|
6,705,544
|
|
|
$
|
5,770,203
|
|
|
$
|
4,305,905
|
|
|
$
|
4,480,470
|
|
Overhead costs included in lease operating expense
|
|
$
|
406,054
|
|
|
$
|
466,796
|
|
|
$
|
548,873
|
|
|
$
|
406,175
|
|
|
$
|
447,213
|
|
Reimbursement of overhead costs*
|
|
$
|
(255,882
|
)
|
|
$
|
(355,235
|
)
|
|
$
|
(353,020
|
)
|
|
$
|
(263,198
|
)
|
|
$
|
(260,742
|
)
|
Capitalized lease equipment and producing leaseholds costs
incurred
|
|
$
|
999,864
|
|
|
$
|
794,822
|
|
|
$
|
1,394,856
|
|
|
$
|
593,366
|
|
|
$
|
2,304,551
|
|
Payment of well development costs
|
|
$
|
1,485,311
|
|
|
$
|
1,004,078
|
|
|
$
|
1,953,828
|
|
|
$
|
745,881
|
|
|
$
|
5,638,441
|
|
Revenue receipts
|
|
$
|
|
|
|
$
|
7,447,596
|
|
|
$
|
8,151,559
|
|
|
$
|
5,000,851
|
|
|
$
|
13,579,071
|
|
With General Partner
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Overhead costs incurred*
|
|
$
|
447,000
|
|
|
$
|
447,000
|
|
|
$
|
447,000
|
|
|
$
|
335,250
|
|
|
$
|
335,250
|
|
With former revenue intermediary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue receipts
|
|
$
|
1,961,996
|
|
|
$
|
5,963,891
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
* |
|
Upon dissolution of the former partnership (see Note A2),
an agreement was reached between the former partners and
operator with Predecessor and new operator. The agreement
provided that the existing overhead agreement would continue to
apply to all working interest owners other than Predecessor.
Predecessor negotiated a new overhead arrangement with lower
rates with the new operator, which includes a reimbursement to
Predecessor for overhead amounts paid by the other working
interest owners. The overhead charges, net of the reimbursement
for the amounts paid by the other working interest owners, is
included in operating expenses in the statements of earnings. |
VOC F-18
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
Following is a summary of balances due to/from related parties:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Former
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
|
Crude Oil
|
|
|
|
|
|
|
Operator
|
|
|
Intermediary
|
|
|
Purchasers
|
|
|
Total
|
|
|
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
1,036,818
|
|
|
$
|
1,438,121
|
|
|
$
|
2,033,430
|
|
|
$
|
4,508,369
|
|
Accounts payable
|
|
$
|
819,583
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
819,583
|
|
Other accrued liabilities
|
|
$
|
95,002
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
95,002
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
2,167,284
|
|
|
$
|
|
|
|
$
|
2,462,780
|
|
|
$
|
4,630,064
|
|
Accounts payable
|
|
$
|
1,285,891
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,285,891
|
|
September 30 2010 (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
3,084,163
|
|
|
$
|
|
|
|
$
|
1,813,148
|
|
|
$
|
4,897,311
|
|
Accounts payable
|
|
$
|
1,415,526
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,415,526
|
|
As publicly reported on July 22, 2008, the revenue
intermediary/crude oil purchaser (Eaglwing L.P.) and its parent
(SemGroup, L.P.) filed voluntary petitions for reorganization
under Chapter 11 of the United States Bankruptcy Code.
During this process, the monies that had been transferred to the
revenue intermediary by certain of Predecessors oil and
gas purchasers for distribution to Predecessor and other working
interest, royalty interest and overriding royalty interest
owners was erroneously retained by the revenue intermediary.
Vess Oil Corporation, as primary operator of Predecessors
oil and gas leases, filed suit to recover these funds which were
estimated to be $1,438,121 for Predecessors ownership. In
addition, Vess Oil Corporation filed a proof of claim for a
statutory lien claim with the bankruptcy court on behalf of the
working interest owners (inclusive of Predecessor interests),
overriding royalty owners and royalty owners. In 2008, as there
was no assurance as to the dollar amount, if any, that would be
recovered or the timing of such recovery, an allowance for
doubtful accounts of $719,061 or 50% of the total estimated
amount owed from Eaglwing, L.P. to Predecessor was established
as of December 31, 2008. In addition, an allowance was set
up for the oil purchased from the Common Control Properties in
the amount of $1,007,594 which represents approximately 87% of
June 2008 sales made to Eaglwing, L.P.
In 2009, Predecessor was successful in its suit and received
$1,430,660 which resulted in a bad debt recovery of $719,061 as
reflected in the 2009 statement of earnings. In regards to
oil sales made to Eaglwing, L.P., Predecessor received 100% of
the sales made to Eaglwing, L.P. from July 2, 2008 through
July 22, 2008 in April 2010 and approximately 13% of the
sales made to Eaglwing from June 1, 2008 through
July 1, 2008 in October 2010.
A summary of sales and trade receivables with MV Purchasing,
LLC, an affiliate of VOC Sponsor, follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
Year Ended December 31,
|
|
|
September 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2009
|
|
|
2010
|
|
|
Sales
|
|
$
|
|
|
|
$
|
646,957
|
|
|
$
|
5,993,119
|
|
|
$
|
4,063,764
|
|
|
$
|
6,239,438
|
|
Trade Receivables
|
|
$
|
|
|
|
$
|
180,841
|
|
|
$
|
610,191
|
|
|
|
|
|
|
$
|
656,226
|
|
VOC F-19
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
MV Purchasing began operations on August 1, 2008.
NOTE F
CONCENTRATION OF CREDIT RISK
Financial instruments, which potentially subject Predecessor to
credit risk, consist primarily of cash, cash equivalents, trade
receivables and swap agreements.
Predecessor maintains cash and cash equivalents with two
financial institutions. At times, such amounts may exceed the
F.D.I.C. limits. Predecessor places its cash and cash
equivalents with high credit quality financial institutions and
believes that no significant concentration of credit risk exists
with respect to these cash investments.
Sales and trade receivables subject Predecessor to the potential
for credit risk with customers. Approximately 82%, 80% and 83%
of Predecessors trade receivables balance at
December 31, 2008 and 2009 and September 30, 2010
(unaudited), respectively, was represented by two, three and two
customers and the revenue intermediaries, respectively.
Approximately 79%, 81%, 74%, 73% and 78% of sales for the years
ended December 31, 2007, 2008 and 2009 and for the nine
months ended September 30, 2009 and 2010 (unaudited),
respectively, were made to three, four, three, three and three
customers respectively. Management continually evaluates the
credit worthiness of the customers and believes net amount
recorded will be received.
Predecessor has entered into certain swap agreements as
discussed in Note D.
NOTE G
ASSET RETIREMENT OBLIGATION
The Predecessors asset retirement obligations are
primarily associated with the plugging and abandoning of oil and
gas properties. The activity in the asset retirement obligation
during the years ended December 31 and for the period ended
September 30, 2010 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
September 30,
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
(Unaudited)
|
|
|
Asset retirement obligation beginning of period
|
|
$
|
2,285,964
|
|
|
$
|
2,641,033
|
|
|
$
|
4,075,952
|
|
|
$
|
3,019,115
|
|
Liabilities incurred during the period
|
|
|
83,668
|
|
|
|
238,516
|
|
|
|
77,632
|
|
|
|
29,978
|
|
Liabilities settled during the period
|
|
|
(1,737
|
)
|
|
|
(25,143
|
)
|
|
|
(27,149
|
)
|
|
|
(235,053
|
)
|
Accretion expense
|
|
|
128,018
|
|
|
|
154,231
|
|
|
|
224,152
|
|
|
|
121,229
|
|
Increase (decrease) in asset retirement obligation due to
changes in timing and changes in estimated cash flows
|
|
|
145,120
|
|
|
|
1,067,315
|
|
|
|
(1,331,472
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation end of period
|
|
|
2,641,033
|
|
|
|
4,075,952
|
|
|
|
3,019,115
|
|
|
|
2,935,269
|
|
Less current portion included in other accrued liabilities
|
|
|
80,844
|
|
|
|
272,037
|
|
|
|
365,439
|
|
|
|
170,404
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term portion
|
|
$
|
2,560,189
|
|
|
$
|
3,803,915
|
|
|
$
|
2,653,676
|
|
|
$
|
2,764,865
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
VOC F-20
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
NOTE H
FAIR VALUE MEASUREMENTS
Effective January 1, 2008, the Predecessor adopted new
accounting guidance for its financial assets and liabilities
measured on a recurring basis. This guidance establishes a
framework for measuring fair value of assets and liabilities and
expands disclosures about fair value measurements. It defines
fair value as the amount that would be received from the sale of
an asset or paid for the transfer of a liability in an orderly
transaction between market participants, i.e., an exit price. To
estimate an exit price, a three-level hierarchy is used. The
fair value hierarchy prioritizes the inputs, which refer broadly
to assumptions market participants would use in pricing an asset
or a liability, into three levels. Level 1 inputs are
unadjusted quoted prices in active markets for identical assets
and liabilities and have the highest priority. Level 2
inputs are inputs other than quoted prices within Level 1
that are observable for the asset or liability, either directly
or indirectly. Level 3 inputs are unobservable inputs for
the financial asset or liability and have the lowest priority.
The carrying amount reported in the combined balance sheets for
cash and cash equivalents, accounts receivable and accounts
payable, accrued expenses and settlements receivable and payable
on oil swap agreements approximates fair value because of the
immediate or short-term maturity of these financial instruments.
The carrying amount reported in the combined balance sheets for
note payable approximates fair value because the actual interest
rates do not significantly differ from current rates offered for
instruments with similar characteristics.
The following table provides fair value measurement information
for financial assets and liabilities measured at fair value on a
recurring basis as of December 31, 2008 and 2009 and
September 30, 2010 (unaudited):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices in
|
|
Significant Other
|
|
Unobservable
|
|
|
Active Markets
|
|
Observable Inputs
|
|
Inputs
|
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
Financial assets (liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 Hedge agreements, net
|
|
$
|
|
|
|
$
|
8,360,873
|
|
|
$
|
|
|
2009 Hedge agreements, net
|
|
$
|
|
|
|
$
|
(209,499
|
)
|
|
$
|
|
|
2010 Hedge agreements, net
|
|
$
|
|
|
|
$
|
1,245,391
|
|
|
$
|
|
|
2008 asset retirement obligations incurred
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(238,516
|
)
|
2009 asset retirement obligations incurred
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(77,632
|
)
|
2010 asset retirement obligations incurred
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(29,978
|
)
|
Level 1
Fair Value Measurements
None.
Level 2
Fair Value Measurements
Hedge agreements The fair value of hedge
agreements has been established utilizing established index
prices, oil future price curves and discount factors. These
estimates are compared to the counterparty values for
reasonableness. The hedge agreements are also subject to the
risk that the counterparty will be unable to meet its
obligations. Such non-performance risk is
VOC F-21
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
considered in the valuation of the hedge agreements, but has not
had a material impact on the values of our hedge agreements.
Level 3
Fair Value Measurements
The initial measurement of asset retirement obligations
fair value is calculated using discounted cash flow techniques
and is based on internal estimates of future retirement costs
associated with oil and gas properties. Given the unobservable
nature of the inputs, including plugging costs and reserve
lives, the initial measurement of the ARO liability is deemed to
use Level 3 inputs. See Notes A13 and G for further
discussion.
NOTE I
COMMITMENTS AND CONTINGENCIES
The Partnership has entered into two drilling authorization for
expenditure (AFE) agreements in late 2009 that total $3,738,210.
As of December 31, 2009, the Partnership has incurred
$843,483 leaving an estimated balance to completion remaining on
these AFEs of $2,894,727.
The Predecessor is involved in legal actions and claims arising
in the ordinary course of business. After discussion with
counsel representing the Predecessor, it is the opinion of
management that these matters will not have a material adverse
effect on the Predecessors financial statements.
NOTE J
SUBSEQUENT EVENTS
Management has reviewed activity from December 31, 2009
through December 29, 2010 which is considered to be the
date through which these financial statements are available to
be issued for events requiring recognition or disclosure.
In 2010, Predecessor has entered into five more drilling AFEs
totaling $5,644,195.
NOTE K
DISCLOSURES ABOUT OIL AND GAS ACTIVITIES (UNAUDITED)
In December 2009, Predecessor adopted revised oil and gas
reserve estimation and disclosure requirements. The primary
impact of the new disclosures is to conform the definition of
proved reserves to the SEC Modernization of Oil and Gas
Reporting rules, which were issued by the SEC at the end of
2008. The new rules revised the definition of proved oil and gas
reserves to require that the average,
first-day-of-the-month
price during the
12-month
period before the end of the year, rather than the year-end
price, be used when estimating whether reserve quantities are
economical to produce. This same
12-month
average price is also used in calculating the aggregate amount
of (and changes in) future cash inflows related to the
standardized measure of discounted future net cash flows. The
rules also allow for the use of reliable technology to estimate
proved oil and gas reserves if those technologies have been
demonstrated to result in reliable conclusions about reserve
volumes. The unaudited supplemental information on oil and gas
exploration and production activities for 2009 has been
presented in accordance with the new reserve estimation and
disclosure rules, which may not be applied retrospectively. The
2006,
VOC F-22
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
2007 and 2008 data are presented in accordance with SEC oil and
gas disclosure requirements effective during those periods.
Estimates of the proved oil and gas reserves attributable to the
Predecessor as of December 31, 2006, 2007, 2008 and 2009
and for the Common Control Properties as of December 31,
2007, 2008 and 2009 are based on reports of Cawley,
Gillespie & Associates, Inc., independent petroleum
and geological engineers, and the contract property management
engineering staff of Predecessor who operate the underlying
properties, in accordance with the provisions of accounting
literature for Oil and Gas Extractive Activities. Users of this
information should be aware that the process of estimating
quantities of proved and proved
developed and proved undeveloped crude 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 additional
development activity, evolving production history and continual
reassessment of the viability of production under varying
economic conditions. Consequently, material revisions to
existing reserve estimates occur from time to time.
The reserve data below represent estimates only and should not
be construed as being exact. Moreover, the discounted values
should not be construed as representative of the current market
value of the oil and gas properties. A market value
determination would include many additional factors including:
(i) anticipated future oil and gas prices; (ii) the
effect of federal income taxes, if any, on Predecessor;
(iii) an allowance for return on investment; (iv) the
effect of governmental legislation; (v) the value of
additional potential reserves, not considered proved at present,
which may be recovered as a result of further exploration and
development activities; and (vi) other business risks.
The following tables set forth (i) the estimated net
quantities of proved, proved developed and proved undeveloped
oil and natural gas reserves attributable to the oil and gas
properties, and (ii) the standardized measure of the
discounted future net profits interest income attributable to
the oil and gas properties and the nature of changes in such
standardized measure between
VOC F-23
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
years. These tables are prepared on the accrual basis, which is
the basis on which Predecessor maintains its production records.
ESTIMATED
QUANTITIES OF OIL AND GAS RESERVES
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
Gas
|
|
|
|
(Bbls)
|
|
|
(Mcf)
|
|
|
Proved reserves:
|
|
|
|
|
|
|
|
|
Balance at December 31, 2006
|
|
|
8,174,154
|
|
|
|
4,573,914
|
|
Revisions, extensions, discoveries and additions
|
|
|
(332,769
|
)
|
|
|
190,995
|
|
Production
|
|
|
(386,879
|
)
|
|
|
(390,593
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
7,454,506
|
|
|
|
4,374,316
|
|
Revisions, extensions, discoveries and additions
|
|
|
(569,089
|
)
|
|
|
276,043
|
|
Production
|
|
|
(389,268
|
)
|
|
|
(426,326
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
6,496,149
|
|
|
|
4,224,033
|
|
Revisions, extensions, discoveries and additions
|
|
|
2,003,848
|
|
|
|
693,788
|
|
Production
|
|
|
(407,415
|
)
|
|
|
(414,730
|
)
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
8,092,582
|
|
|
|
4,503,091
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
7,497,626
|
|
|
|
4,243,531
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
6,877,406
|
|
|
|
4,116,158
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
5,770,190
|
|
|
|
3,928,995
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
6,729,632
|
|
|
|
3,854,008
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
676,528
|
|
|
|
330,383
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
577,100
|
|
|
|
258,158
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
725,959
|
|
|
|
295,038
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
1,362,950
|
|
|
|
649,083
|
|
|
|
|
|
|
|
|
|
|
STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
FROM PROVED OIL AND GAS RESERVES
Future oil and natural gas sales and production and development
costs have been estimated in accordance with the SEC
Modernization of Oil and Gas Reporting Rules.
The standardized measure of discounted future net cash flows
(the Standardized Measure) represents the present
value of estimated future cash inflows from proved oil and
natural gas reserves, less future development, production and
plugging and abandonment costs, discounted at 10% per annum to
reflect timing of future cash flows. Production costs do not
include depreciation, depletion and amortization of capitalized
acquisition, exploration and development costs. Because
Predecessor bears no federal income tax expense and taxable
income is passed
VOC F-24
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
through to the partners of Predecessor, no provision for federal
or state income taxes is included in the reserve report or in
the calculation of the Standardized Measure.
Estimated proved reserves and related future net revenues and
Standardized Measure were determined using index prices for oil
and natural gas, without giving effect to derivative
transactions, and were held constant throughout the life of the
properties. The index prices were $90.83/Bbl for oil and
$7.47/Mcf for natural gas at December 31, 2007, $39.49/Bbl
for oil and $5.61/Mcf for natural gas at December 31, 2008,
and the unweighted arithmetic average
first-day
of-the-month
prices for the prior 12 months were $55.82/Bbl for oil and
$4.58/Mcf for natural gas at December 31, 2009. These
prices were adjusted in the case of crude oil for forecasted
gravity, quality, transportation and marketing as well as other
factors affecting the price received at the wellhead. The impact
of the adoption of the authoritative guidance of the Financial
Accounting Standard Board (the FASB) on the SEC oil
and gas reserve estimation final rule on our financial
statements is not practicable to estimate due to the operation
and technical challenges associated with calculating a
cumulative effect of adoption by preparing reserve reports under
both the old and new rules.
Changes in the demand for oil and natural gas, inflation, and
other factors made such estimates inherently imprecise and
subject to substantial revision. This table should not be
construed to be an estimate of current market value of the
proved reserves attributable to Predecessors reserves.
The estimated Standardized Measure relating to
Predecessors proved reserves at December 31, 2007,
2008 and 2009 is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Future cash inflows
|
|
$
|
709,982,661
|
|
|
$
|
285,599,020
|
|
|
$
|
479,804,227
|
|
Future costs
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
(230,390,861
|
)
|
|
|
(152,898,120
|
)
|
|
|
(192,121,342
|
)
|
Development
|
|
|
(8,755,334
|
)
|
|
|
(12,501,184
|
)
|
|
|
(25,183,887
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
470,836,466
|
|
|
|
120,199,716
|
|
|
|
262,498,998
|
|
Less 10% discount factor
|
|
|
(264,326,635
|
)
|
|
|
(60,259,262
|
)
|
|
|
(142,117,093
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
206,509,831
|
|
|
$
|
59,940,454
|
|
|
$
|
120,381,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
VOC F-25
Predecessor
NOTES TO
COMBINED FINANCIAL STATEMENTS (Continued)
For the years ended December 31, 2007, 2008 and 2009
and the nine months ended September 30, 2009 and 2010
(information for the nine months ended September 30, 2009
and 2010 is unaudited)
The following table sets forth the changes in the Standardized
Measure applicable to Predecessors proved oil and natural
gas reserves for the years ended December 31, 2007, 2008
and 2009:
CHANGES
IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH
FLOWS FROM PROVED OIL AND GAS RESERVES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
Standardized measure at beginning of year
|
|
$
|
151,282,536
|
|
|
$
|
206,509,831
|
|
|
$
|
59,940,454
|
|
Sales of oil and gas produced, net of production costs
|
|
|
(20,049,955
|
)
|
|
|
(29,744,163
|
)
|
|
|
(15,788,110
|
)
|
Net changes in price and production costs
|
|
|
68,207,350
|
|
|
|
(154,948,134
|
)
|
|
|
41,400,518
|
|
Changes in estimated future development costs
|
|
|
222,643
|
|
|
|
(2,726,749
|
)
|
|
|
(14,381,027
|
)
|
Development costs incurred during the period which reduce future
development costs
|
|
|
1,200,100
|
|
|
|
52,800
|
|
|
|
2,700,100
|
|
Revisions of quantity estimates
|
|
|
(8,530,591
|
)
|
|
|
(5,476,929
|
)
|
|
|
32,773,504
|
|
Accretion of discount
|
|
|
15,128,254
|
|
|
|
20,650,983
|
|
|
|
5,994,045
|
|
Change in production rates, timing and other
|
|
|
(950,506
|
)
|
|
|
25,622,815
|
|
|
|
7,742,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure at end of year
|
|
$
|
206,509,831
|
|
|
$
|
59,940,454
|
|
|
$
|
120,381,905
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
VOC F-26
Predecessor
The following unaudited pro forma financial statements have been
prepared to illustrate the acquisition of the Acquired
Properties and the conveyance of a net profits interest in all
the underlying properties by VOC Sponsor to the Trust and
distribution by VOC Sponsor to its limited partners of the net
proceeds of this offering including the sale of trust units to
VOC Partners, LLC, an affiliate of VOC Sponsor, 45 days
after the closing of this offering. The unaudited pro forma
balance sheet is presented as of September 30, 2010, giving
effect to the acquisition of the Acquired Properties, the
issuance
of trust
units at $ per unit,
the net profits interest conveyance and the payment of VOC
Sponsors distribution by VOC Sponsor to its limited
partners of the net proceeds of this offering as if they
occurred on September 30, 2010. The unaudited pro forma
statements of earnings present the historical statements of
earnings of VOC Sponsor for the year ended December 31,
2009 and the nine months ended September 30, 2010, giving
effect to the acquisition of the Acquired Properties and to the
net profits interest conveyance and the distribution by VOC
Sponsor to its limited partners as if they occurred as of
January 1, 2009 reflecting only pro forma adjustments
expected to have a continuing impact on the combined results.
These unaudited pro forma financial statements are for
informational purposes only. They do not purport to present the
results that would have actually occurred had the unit offering,
net profits interest conveyance and the distribution by VOC
Sponsor to its limited partners of the net proceeds of this
offering been completed on the assumed dates or for the periods
presented. Moreover, they do not purport to project VOC
Sponsors financial position or results of operations for
any future date or period.
To produce the pro forma financial information, management made
certain estimates. These estimates are based on the most
recently available information. To the extent there are
significant changes in these amounts, the assumptions and
estimates herein could change significantly. The unaudited pro
forma financial statements should be read in conjunction with
the accompanying notes to such unaudited pro forma financial
statements, Managements Discussion and Analysis of
Financial Condition and Results of Operations of VOC
Sponsor and the audited historical financial statements of
Predecessor included in this prospectus and elsewhere in the
registration statement.
VOC F-27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
Pro Forma
|
|
|
|
Historical
|
|
|
Adjustments (a)
|
|
|
Pro Forma
|
|
|
Adjustments
|
|
|
as Adjusted
|
|
|
Cash and cash equivalents
|
|
$
|
10,041,005
|
|
|
$
|
13,178
|
|
|
$
|
10,054,183
|
|
|
|
|
(b)
|
|
|
10,054,183
|
|
Accounts receivable oil and gas sales
|
|
|
938,871
|
|
|
|
1,014,020
|
|
|
|
1,952,891
|
|
|
|
|
|
|
|
1,952,891
|
|
Accounts receivable oil and gas sales
related parties, net of allowance for doubtful accounts of
$1,007,594
|
|
|
3,889,717
|
|
|
|
1,074,812
|
|
|
|
4,964,529
|
|
|
|
|
|
|
|
4,964,529
|
|
Settlement receivable on oil swap agreements
|
|
|
31,262
|
|
|
|
|
|
|
|
31,262
|
|
|
|
|
|
|
|
31,262
|
|
Receivable from Trust
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
339,234
|
(d)
|
|
|
339,234
|
|
Note receivable related parties
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33,097,222
|
(c)
|
|
|
33,097,222
|
|
Oil Swap agreements
|
|
|
911,691
|
|
|
|
|
|
|
|
911,691
|
|
|
|
|
|
|
|
911,691
|
|
Prepaid expenses
|
|
|
127,200
|
|
|
|
|
|
|
|
127,200
|
|
|
|
|
|
|
|
127,200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
15,939,746
|
|
|
|
2,102,010
|
|
|
|
18,041,756
|
|
|
|
33,436,456
|
|
|
|
51,478,212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OIL AND GAS PROPERTIES
|
|
|
118,974,942
|
|
|
|
61,206,695
|
|
|
|
180,181,637
|
|
|
|
(144,145,310
|
)(d)
|
|
|
36,036,327
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
26,331,798
|
|
|
|
|
|
|
|
26,331,798
|
|
|
|
(21,065,438
|
) (d)
|
|
|
5,266,360
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
92,643,144
|
|
|
|
61,206,695
|
|
|
|
153,849,839
|
|
|
|
(123,079,872
|
) (d)
|
|
|
30,769,967
|
|
OTHER ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil swap agreements
|
|
|
333,700
|
|
|
|
|
|
|
|
333,700
|
|
|
|
|
|
|
|
333,700
|
|
Receivable from Trust
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,942,872
|
(d)
|
|
|
1,942,872
|
|
Deferred loan costs, net of accumulated amortization of
$1,263,354
|
|
|
695,527
|
|
|
|
|
|
|
|
695,527
|
|
|
|
|
|
|
|
695,527
|
|
Deferred offering costs
|
|
|
14,268
|
|
|
|
336,048
|
|
|
|
350,316
|
|
|
|
(350,316
|
) (e)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,043,495
|
|
|
|
336,048
|
|
|
|
1,379,543
|
|
|
|
1,592,556
|
|
|
|
2,972,099
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
109,626,385
|
|
|
$
|
63,644,753
|
|
|
$
|
173,271,138
|
|
|
$
|
(88,050,860
|
)
|
|
$
|
85,220,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL/COMMON CONTROL
OWNERS EQUITY (DEFICIT)
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade
|
|
$
|
12,286
|
|
|
$
|
127,356
|
|
|
$
|
139,642
|
|
|
$
|
|
|
|
$
|
139,642
|
|
Related parties
|
|
|
1,415,526
|
|
|
|
615,059
|
|
|
|
2,030,585
|
|
|
|
|
|
|
|
2,030,585
|
|
Accrued interest
|
|
|
125,811
|
|
|
|
|
|
|
|
125,811
|
|
|
|
|
|
|
|
125,811
|
|
Settlement payable on oil swap agreements
|
|
|
35,757
|
|
|
|
|
|
|
|
35,757
|
|
|
|
|
|
|
|
35,757
|
|
Accrued ad valorem taxes
|
|
|
890,631
|
|
|
|
496,458
|
|
|
|
1,387,089
|
|
|
|
|
|
|
|
1,387,089
|
|
Other accrued liabilities
|
|
|
182,376
|
|
|
|
403,770
|
|
|
|
586,146
|
|
|
|
|
|
|
|
586,146
|
|
Due to Trust
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
729,353
|
(d)
|
|
|
729,353
|
|
Deferred gain on sale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,235,963
|
(e)
|
|
|
7,235,963
|
|
Current maturities of notes payable
|
|
|
267,193
|
|
|
|
|
|
|
|
267,193
|
|
|
|
|
|
|
|
267,193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
2,929,580
|
|
|
|
1,642,643
|
|
|
|
4,572,223
|
|
|
|
7,965,316
|
|
|
|
12,537,539
|
|
LONG-TERM LIABILITIES, less current maturities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes payable
|
|
|
24,000,000
|
|
|
|
|
|
|
|
24,000,000
|
|
|
|
|
|
|
|
24,000,000
|
|
Deferred gain on sale
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73,174,296
|
(e)
|
|
|
73,174,296
|
|
Due to Trust
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
266,960
|
(d)
|
|
|
266,960
|
|
Asset retirement obligation
|
|
|
2,764,865
|
|
|
|
2,057,585
|
|
|
|
4,822,450
|
|
|
|
|
|
|
|
4,822,450
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,764,865
|
|
|
|
2,057,585
|
|
|
|
28,822,450
|
|
|
|
73,441,256
|
|
|
|
102,263,706
|
|
PARTNERS CAPITAL/COMMON CONTROL OWNERS EQUITY
(DEFICIT)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner capital account
|
|
|
697,791
|
|
|
|
|
|
|
|
697,791
|
|
|
|
(1,349,220
|
)(f)
|
|
|
(651,429
|
)
|
Limited partner capital account
|
|
|
57,776,184
|
|
|
|
|
|
|
|
57,776,184
|
|
|
|
(66,121,443
|
) (g)
|
|
|
(8,345,259
|
)
|
Common control owners equity
|
|
|
20,513,302
|
|
|
|
59,944,525
|
|
|
|
80,457,827
|
|
|
|
(101,986,769
|
) (h)
|
|
|
(21,528,942
|
)
|
Accumulated other comprehensive income
|
|
|
944,663
|
|
|
|
|
|
|
|
944,663
|
|
|
|
|
|
|
|
944,663
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
79,931,940
|
|
|
|
59,944,525
|
|
|
|
139,876,465
|
|
|
|
(169,457,432
|
)
|
|
|
(29,580,967
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
109,626,385
|
|
|
$
|
63,644,753
|
|
|
$
|
173,271,138
|
|
|
$
|
(88,050,860
|
)
|
|
$
|
85,220,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these unaudited pro forma financial statements.
VOC F-28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
Nine Months Ended September 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro
|
|
|
|
|
|
|
(a)
|
|
|
Pro
|
|
|
Additional
|
|
|
Forma as
|
|
|
|
|
|
|
(a)
|
|
|
Pro
|
|
|
Additional
|
|
|
Forma as
|
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Forma
|
|
|
Adjustments
|
|
|
Adjusted
|
|
|
|
Historical
|
|
|
Adjustments
|
|
|
Forma
|
|
|
Adjustments
|
|
|
Adjusted
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
25,745,771
|
|
|
$
|
18,383,029
|
|
|
$
|
44,128,800
|
|
|
$
|
(35,303,040
|
)(i)
|
|
$
|
8,825,760
|
|
|
|
$
|
29,089,570
|
|
|
$
|
17,981,276
|
|
|
$
|
47,070,846
|
|
|
$
|
(37,656,677
|
)(i)
|
|
$
|
9,414,169
|
|
Gain on sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,005,413
|
(j)
|
|
|
7,005,413
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,216,956
|
(j)
|
|
|
5,216,956
|
|
Other
|
|
|
4,452
|
|
|
|
|
|
|
|
4,452
|
|
|
|
|
|
|
|
4,452
|
|
|
|
|
1,681
|
|
|
|
|
|
|
|
1,681
|
|
|
|
|
|
|
|
1,681
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,750,223
|
|
|
|
18,383,029
|
|
|
|
44,133,252
|
|
|
|
(28,297,627
|
)
|
|
|
15,835,625
|
|
|
|
|
29,091,251
|
|
|
|
17,981,276
|
|
|
|
47,072,527
|
|
|
|
(32,439,721
|
)
|
|
|
14,632,806
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
6,787,857
|
|
|
|
5,969,210
|
|
|
|
12,757,067
|
|
|
|
(10,205,654
|
)(k)
|
|
|
2,551,413
|
|
|
|
|
5,228,613
|
|
|
|
4,690,168
|
|
|
|
9,918,781
|
|
|
|
(7,935,024
|
)(k)
|
|
|
1,983,757
|
|
Production and property taxes
|
|
|
1,646,052
|
|
|
|
1,169,799
|
|
|
|
2,815,851
|
|
|
|
(2,252,681
|
)(l)
|
|
|
563,170
|
|
|
|
|
1,918,959
|
|
|
|
950,133
|
|
|
|
2,869,092
|
|
|
|
(2,295,274
|
)(l)
|
|
|
573,818
|
|
Depreciation, depletion, amortization and accretion
|
|
|
5,210,212
|
|
|
|
4,883,586
|
|
|
|
10,093,798
|
|
|
|
(7,847,694
|
)(m)
|
|
|
2,246,104
|
|
|
|
|
4,354,677
|
|
|
|
3,369,504
|
|
|
|
7,724,181
|
|
|
|
(5,968,621
|
)(m)
|
|
|
1,755,560
|
|
Interest expense
|
|
|
1,500,647
|
|
|
|
|
|
|
|
1,500,647
|
|
|
|
|
|
|
|
1,500,647
|
|
|
|
|
920,104
|
|
|
|
|
|
|
|
920,104
|
|
|
|
|
|
|
|
920,104
|
|
Bad debt expense (recovery)
|
|
|
(719,061
|
)
|
|
|
|
|
|
|
(719,061
|
)
|
|
|
|
|
|
|
(719,061
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
463,295
|
|
|
|
|
|
|
|
463,295
|
|
|
|
|
|
|
|
463,295
|
|
|
|
|
111,576
|
|
|
|
18,518
|
|
|
|
130,094
|
|
|
|
|
|
|
|
130,094
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
14,889,002
|
|
|
|
12,022,595
|
|
|
|
26,911,597
|
|
|
|
(20,306,029
|
)
|
|
|
6,605,568
|
|
|
|
|
12,533,929
|
|
|
|
9,028,323
|
|
|
|
21,562,252
|
|
|
|
(16,198,919
|
)
|
|
|
5,363,333
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
$
|
10,861,221
|
|
|
$
|
6,360,434
|
|
|
$
|
17,221,655
|
|
|
$
|
(7,991,598
|
)
|
|
$
|
9,230,057
|
|
|
|
$
|
16,557,322
|
|
|
$
|
8,952,953
|
|
|
$
|
25,510,275
|
|
|
$
|
(16,240,802
|
)
|
|
$
|
9,269,473
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an
integral part of these unaudited pro forma financial statements.
VOC F-29
Predecessor
NOTE A
BASIS OF PRESENTATION
VOC Sponsor will convey the net profits interest in oil and
natural gas producing properties located in the States of Kansas
and Texas to the VOC Energy Trust (the Trust). The
net profits interest entitles the Trust to receive 80% of the
net proceeds attributable to VOC Sponsors interest from
the sale of production from the underlying properties. The net
profits interest will terminate and the underlying properties
will revert back to VOC Sponsor on the later to occur of
(1) December 31, 2030, or (2) when 9.7 MMBoe
have been produced from the underlying properties and sold.
The net proceeds of the offering will be used to distribute
$169.5 million to the partners of VOC Sponsor.
The unaudited pro forma balance sheet assumes the issuance
of
trust units at $ per unit and
estimated direct transaction costs to be incurred by VOC Sponsor
of approximately $ million
(comprised of underwriter, legal, accounting and other fees). As
of September 30, 2010, VOC Sponsor had incurred $350
thousand of these direct transaction costs.
VOC Sponsor will
sell
of the trust units to the public for cash of
$ million and recognize a
deferred gain of $80.4 million. The deferred gain will be
recognized in income over the life of the net profits interest
based on production. Forty-five days after the closing of this
offering, VOC Sponsor will also
sell
of the trust units to VOC Partners, LLC, an affiliate of VOC
Sponsor, in exchange for $9.3 million in cash and notes
receivable for $83.6 million in the aggregate. The notes
will be paid off in forty (40) quarterly payments beginning
July 2011, including interest at 5.0%. The notes will be
collateralized by each partners ownership interest in VOC
Partners. In accordance with accounting rules for transactions
among related parties, the notes receivable were recorded at the
historical carrying value of the trust units sold to the members
and no gain on sale has been reflected. The excess of payments
over the historical carrying value will be recorded as capital
contributions by the members.
VOC Sponsor has entered into hedge arrangements with
institutional third parties with respect to the volumes of oil
production for the periods covered by these pro forma statements
and the years following until 2011 such that VOC Sponsor would
be entitled to receive payments from the counterparties in the
event that reference prices for oil contracts traded on NYMEX
for the periods covered are less than the fixed prices specified
for the hedge and other derivatives. VOC Sponsor will also be
required to make payments to the counterparties in the event
that reference prices for oil contracts traded on NYMEX for the
periods covered are more than the fixed prices specified for the
hedge arrangements. Although these hedge and other derivative
arrangements will not be directly dedicated or pledged to the
Trust, VOC Sponsor expects that payments received or made
by it under these hedge arrangements will affect its financial
obligations to make payments to the Trust. The effects of these
hedge and other derivative arrangements, if any, are reflected
in these unaudited pro forma financial statements.
NOTE B
PRO FORMA ADJUSTMENTS
Pro forma adjustments are necessary to reflect the issuance of
the trust units, the conveyance of the net profits interest, the
sale of trust units and the payment of VOC Sponsors
long-term
VOC F-30
obligations and distributions using proceeds from the offering.
The pro forma adjustments included in the unaudited pro forma
balance sheet are as follows:
|
|
(a) |
Pro forma adjustments necessary to record the acquisition of the
Acquired Properties oil and gas related assets at estimated fair
value (at December 31, 2009), liabilities, owners
equity and oil and gas revenues and related expenses.
|
Additional pro forma adjustments are necessary to reflect the
issuance of the trust units, the conveyance of the net profits
interest, the sale of trust units and the payment of VOC
Sponsors distributions using proceeds from the offering.
The pro forma adjustments included in the unaudited pro forma
balance sheet are as follows:
|
|
|
|
|
|
|
|
|
|
|
September 30, 2010
|
|
|
(b)
|
|
Gross cash proceeds from the sale of the trust units
|
|
$
|
174,000,000
|
|
|
|
Cash down payment on related party note
|
|
|
9,287,116
|
|
|
|
Payment of estimated remaining transaction fees and costs from
the sale of trust units
|
|
|
(13,829,684
|
)
|
|
|
Distribution to members
|
|
|
(169,457,432
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
(c)
|
|
Receivable from related party for sale of 34.8% of trust units
at historical value
|
|
$
|
42,384,338
|
|
|
|
Cash down payment on receivable
|
|
|
9,287,116
|
|
|
|
|
|
|
|
|
|
|
Remaining receivable from related party for sale of 34.8% of
trust units
|
|
$
|
33,097,222
|
|
|
|
|
|
|
|
|
(d)
|
|
Current payable for conveyance of oil swap agreements to the
Trust
|
|
$
|
729,353
|
|
|
|
Long-term payable for conveyance of oil swap agreements to the
Trust
|
|
|
266,960
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
996,313
|
|
|
|
|
|
|
|
|
|
|
Reduction of oil and gas properties due to conveyance of net
profits interest
|
|
$
|
(144,145,310
|
)
|
|
|
Reduction of associated accumulated depreciation, depletion, and
amortization
|
|
|
21,065,438
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(123,079,872
|
)
|
|
|
|
|
|
|
|
|
|
Current receivable from Trust for conveyance of asset retirement
obligation
|
|
$
|
339,234
|
|
|
|
Long-term receivable from Trust for conveyance of asset
retirement obligation
|
|
|
1,942,872
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,282,106
|
|
|
|
|
|
|
|
|
|
|
Net oil and gas properties and equipment
|
|
$
|
153,849,839
|
|
|
|
Asset retirement obligation liability
|
|
|
(2,852,632
|
)
|
|
|
Oil swap agreements
|
|
|
1,245,391
|
|
|
|
|
|
|
|
|
|
|
|
|
|
152,242,598
|
|
|
|
|
|
|
|
|
|
|
80% Net Profits Interest
|
|
$
|
121,794,078
|
|
|
|
|
|
|
|
|
(e)
|
|
Deferred gain on sale of net profits interest is calculated as
follows:
|
|
|
|
|
|
|
Gross cash proceeds from the sale of the trust units
|
|
$
|
174,000,000
|
|
|
|
Less: Net book value of conveyed net profits interests
|
|
|
(79,409,741
|
)
|
|
|
Deferred transaction fees and costs incurred as of
September 30, 2010
|
|
|
(350,316
|
)
|
|
|
Payment of Underwriting discounts, structuring fees and other
offering expenses
|
|
|
(13,829,684
|
)
|
|
|
|
|
|
|
|
|
|
Deferred gain on sale
|
|
$
|
80,410,259
|
|
|
|
|
|
|
|
|
|
|
Current portion of deferred gain
|
|
$
|
7,235,963
|
|
|
|
Long-term portion of deferred gain
|
|
$
|
73,174,296
|
|
|
|
|
|
|
|
|
(f)
|
|
To record distribution of remaining cash to general partner
|
|
$
|
(1,349,220
|
)
|
|
|
|
|
|
|
|
(g)
|
|
To record distribution of remaining cash to limited partner
|
|
$
|
(66,121,443
|
)
|
|
|
|
|
|
|
|
(h)
|
|
To record distribution of remaining cash to common control owners
|
|
$
|
(101,986,769
|
)
|
|
|
|
|
|
|
|
VOC F-31
The pro forma adjustments included in the unaudited pro forma
statements of earnings are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Nine Months Ended
|
|
|
|
|
|
December 31, 2009
|
|
|
September 30, 2010
|
|
|
(i)
|
|
Decrease in oil and gas sales attributable to net profits
interest
|
|
$
|
(35,303,040
|
)
|
|
$
|
(37,656,677
|
)
|
|
|
|
|
|
|
|
|
|
|
|
(j)
|
|
To record amortization of gain on sale of trust units over the
life of the trust
|
|
$
|
7,005,413
|
|
|
$
|
5,216,956
|
|
|
|
|
|
|
|
|
|
|
|
|
(k)
|
|
Decrease in lease operating expenses attributable to the net
profits interest
|
|
$
|
(10,205,654
|
)
|
|
$
|
(7,935,024
|
)
|
|
|
|
|
|
|
|
|
|
|
|
(l)
|
|
Decrease in production and property taxes attributable to the
net profits interest
|
|
$
|
(2,252,681
|
)
|
|
$
|
(2,295,274
|
)
|
|
|
|
|
|
|
|
|
|
|
|
(m)
|
|
Reduce depreciation on assets sold to Trust
|
|
$
|
(7,847,694
|
)
|
|
$
|
(5,968,621
|
)
|
|
|
|
|
|
|
|
|
|
|
|
VOC F-32
APPENDIX A
SUMMARIES
OF RESERVE REPORTS
March 22,
2010
Mr. Bill Horigan
Vess Oil Corporation
1700 Waterfront Pkwy, Bldg 500
Wichita, KS 67206
|
|
|
|
|
|
|
Re:
|
|
Evaluation Summary
VOC Brazos Energy Partners, L.P. Interests
Total Proved Reserves
Brazos and Smith Counties, Texas
As of January 1, 2010
|
Dear Mr. Horigan:
As requested, this report was prepared on March 22, 2010
for VOC Brazos Energy Partners, L.P. interests
(Company) for the purpose of submitting our
estimates of total proved reserves and forecasts of economics
attributable to Company interests. We evaluated 100% of the
Company reserves, which are made up of various oil and gas
properties in Brazos and Smith Counties, Texas. This evaluation
utilized an effective date of January 01, 2010, and was
prepared using constant prices and costs and conforms to the
guidelines of the Securities and Exchange Commission
(SEC). A composite summary of the proved reserves is
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
Proved
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
Developed
|
|
|
Proved
|
|
|
Total
|
|
|
|
|
|
Producing
|
|
|
Non-Producing
|
|
|
Undeveloped
|
|
|
Proved
|
|
|
Net Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
Mbbl
|
|
|
3,836.3
|
|
|
|
378.1
|
|
|
|
1,363.0
|
|
|
|
5,577.4
|
|
Gas
|
|
MMcf
|
|
|
1,902.0
|
|
|
|
180.4
|
|
|
|
649.1
|
|
|
|
2,731.5
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
M$
|
|
|
219,756.3
|
|
|
|
21,937.3
|
|
|
|
80,222.0
|
|
|
|
321,915.5
|
|
Gas
|
|
M$
|
|
|
12,897.5
|
|
|
|
1,135.6
|
|
|
|
3,164.4
|
|
|
|
17,197.5
|
|
Severance Taxes
|
|
M$
|
|
|
10,447.4
|
|
|
|
1,094.3
|
|
|
|
3,927.5
|
|
|
|
15,469.2
|
|
Ad Valorem Taxes
|
|
M$
|
|
|
6,378.4
|
|
|
|
658.0
|
|
|
|
2,480.1
|
|
|
|
9,516.5
|
|
Operating Expenses
|
|
M$
|
|
|
81,383.0
|
|
|
|
3,847.0
|
|
|
|
8,268.8
|
|
|
|
93,498.6
|
|
Workover Expenses
|
|
M$
|
|
|
3,725.5
|
|
|
|
0.0
|
|
|
|
0.0
|
|
|
|
3,725.5
|
|
3rd Party
COPAS
|
|
M$
|
|
|
0.0
|
|
|
|
0.0
|
|
|
|
0.0
|
|
|
|
0.0
|
|
Other Deductions
|
|
M$
|
|
|
2,481.7
|
|
|
|
100.7
|
|
|
|
203.5
|
|
|
|
2,786.0
|
|
Investments
|
|
M$
|
|
|
0.0
|
|
|
|
3,344.8
|
|
|
|
21,448.6
|
|
|
|
24,793.3
|
|
Net Operating Income
|
|
M$
|
|
|
128,238.0
|
|
|
|
14,028.1
|
|
|
|
47,057.9
|
|
|
|
189,323.9
|
|
Discounted @ 10%
|
|
M$
|
|
|
56,090.4
|
|
|
|
7,286.6
|
|
|
|
18,253.6
|
|
|
|
81,630.5
|
|
The discounted cash flow value shown above should not be
construed to represent an estimate of the fair market value by
Cawley, Gillespie & Associates, Inc.
(CG&A)
Annex A-1
VOC
Brazos Energy Partners, L.P. Interests
March 22,
2010
Presentation
This report is divided into four main sections: Summary
(TP), Proved Developed Producing (PDP),
Proved Developed Non-Producing (PDNP) and Proved
Undeveloped (PUD). Within each reserve category
section are grand total Table Is and Table II
summaries. The Table Is present composite reserve
estimates and economic forecasts for the particular reserve
category. Following Table I are two Table II
oneline summaries that present estimates of ultimate
recovery, gross and net reserves, ownership, revenue, expenses,
investments, net income and discounted cash flow
(DCF) for the individual properties that make up the
corresponding Table I. The first Table II is sorted by
property on DCF value, and the second Table II is sorted by
field and property.
For a more detailed description of the report layout, please
refer to the Table of Contents following this letter. The data
presented in each Table I is explained in page 1 of the
Appendix. The methods employed in estimating reserves are
described in page 2 of the Appendix.
Hydrocarbon
Pricing
As provided, oil and gas prices were adjusted to the following
index prices:
|
|
|
|
|
|
|
|
|
|
|
WTI Cushing
|
|
Henry Hub
|
|
|
Crude Oil
|
|
Natural Gas
|
Year
|
|
$/STB
|
|
$/MMBTU
|
|
2010
|
|
|
61.18
|
|
|
|
3.833
|
|
Thereafter
|
|
|
61.18
|
|
|
|
3.833
|
|
As specified by the SEC, the above prices are
12-month
averages based upon the price on the first day of each month
during 2009. Adjustments to oil and gas prices were made based
upon data provided by your office. These adjustments include
treating cost, transportation charges
and/or crude
quality and gravity corrections. Gas prices were further
adjusted with a heating value (BTU content) applied on a
per-property basis.
Expenses
and Taxes
Lease operating expenses, workover expenses, investments and
other deductions were forecast as furnished by your office. As
requested, LOE and investments were not escalated. Other
Deductions (column 27) represents the net overhead charges
as per the JOA. Severance tax values were determined by applying
normal state severance tax rates. Ad valorem tax rates were
forecast as provided by your office.
MISCELLANEOUS
An on-site
field inspection of the properties has not been performed
nor has the mechanical operation or condition of the wells and
their related facilities been examined, nor have the wells been
tested by Cawley, Gillespie & Associates, Inc.
Possible environmental liability related to the properties has
not been investigated nor considered. The cost of
plugging and the salvage value of equipment at abandonment have
not been included except as noted above.
The proved reserve classifications used herein conform to the
criteria of the Securities and Exchange Commission as defined in
pages 3 and 4 of the Appendix. The reserves and economics
Annex A-2
VOC
Brazos Energy Partners, L.P. Interests
March 22, 2010
are predicated on regulatory agency classifications, rules,
policies, laws, taxes and royalties in effect on the effective
date, except as noted herein. The possible effects of changes in
legislation or other Federal or State restrictive actions have
not been considered. However, we do not anticipate nor are we
aware of any legislative changes or restrictive regulatory
actions that may impact the recovery of reserves. The
assumptions, data, methods and procedures used herein are
appropriate for the purpose served by this report. It should be
realized that the reserves actually recovered, the revenue
derived therefrom and the actual cost incurred could be more or
less than the estimated amounts.
The reserve estimates and forecasts were based upon
interpretations of data furnished by your office and available
from our files. Ownership information and economic factors such
as liquid and gas prices, price differentials, expenses,
investments and tax rates were furnished by your office and were
accepted as furnished. To some extent, information from public
records was used to check
and/or
supplement these data. The basic engineering and geological data
were utilized subject to third party reservations and
qualifications. Nothing has come to our attention, however, that
would cause us to believe that we are not justified in relying
on such data.
This report was prepared for the exclusive use of VOC Brazos
Energy Partners, L.P. Third parties should not rely on it
without the written consent of the above and Cawley,
Gillespie & Associates, Inc. We are independent
registered professional engineers and geologists. We have used
all methods and procedures that we consider necessary under the
circumstances to prepare this report. We do not own an interest
in the properties or VOC Brazos Energy Partners, L.P. and
are not employed on a contingent basis. Our work papers and
related data are available for inspection and review by
authorized, interested parties.
Yours very truly,
/s/ Cawley,
Gillespie & Associates, Inc.
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm (F-693)
Annex A-3
October 20,
2010
|
Mr. Bill Horigan
Vess Oil Corporation
1700 Waterfront Pkwy, Bldg 500
Wichita, Kansas 67206
|
|
|
|
|
|
|
|
|
|
|
Re:
|
|
|
Evaluation Summary
|
|
|
|
|
|
|
VOC Kansas Energy Partners, LLC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Composite of Various Interest Groups
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Certain Properties in Kansas & Texas
|
|
|
|
|
|
|
Total Proved Reserves
|
|
|
|
|
|
|
As of December 31, 2009
|
Dear Mr. Horigan:
As requested, this report was prepared on October 20, 2010
for Vess Oil Corporation (Company) for the
purpose of submitting our estimates of total proved reserves and
forecasts of economics attributable to the VOC Kansas Energy
Partners, LLC (VOC-KEP) interests, which is a
composite of various working interest groups. We evaluated 100%
of the VOC-KEP reserves, which are made up of various oil and
gas properties in Kansas and Texas. This evaluation utilized an
effective date of December 31, 2009, and was prepared using
constant prices and costs and conforms to the guidelines of the
Securities and Exchange Commission (SEC). A composite
summary of the proved reserves is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
|
Proved
|
|
|
|
|
|
|
Developed
|
|
|
Developed
|
|
|
Total
|
|
|
|
Producing
|
|
|
Non-Producing
|
|
|
Proved
|
|
|
Net Reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
6,209.9
|
|
|
|
143.0
|
|
|
|
6,352.9
|
|
Gas
|
|
|
3,731.0
|
|
|
|
0.0
|
|
|
|
3,731.0
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
334,898.6
|
|
|
|
7,713.1
|
|
|
|
342,611.8
|
|
Gas
|
|
|
10,666.6
|
|
|
|
0.0
|
|
|
|
10,666.6
|
|
Severance Taxes
|
|
|
3,469.9
|
|
|
|
0.0
|
|
|
|
3,469.9
|
|
Ad Valorem Taxes
|
|
|
11,541.8
|
|
|
|
388.5
|
|
|
|
11,930.4
|
|
Operating Expenses
|
|
|
128,561.1
|
|
|
|
1,358.5
|
|
|
|
129,919.6
|
|
Workover Expenses
|
|
|
0.0
|
|
|
|
0.0
|
|
|
|
0.0
|
|
COPAS
|
|
|
25,024.1
|
|
|
|
266.5
|
|
|
|
25,290.6
|
|
Investments
|
|
|
0.0
|
|
|
|
523.6
|
|
|
|
523.6
|
|
Net Operating Income
|
|
|
176,968.3
|
|
|
|
5,176.0
|
|
|
|
182,144.3
|
|
Discounted @ 10%
|
|
|
94,549.7
|
|
|
|
2,509.7
|
|
|
|
97,059.3
|
|
The discounted cash flow value shown above should not be
construed to represent an estimate of the fair market value by
Cawley, Gillespie & Associates, Inc.
(CG&A)
Annex A-4
VOC Kansas
Energy Partners, LLC
October 20, 2010
Presentation
This report is divided into three main sections: Summary
(TP), Proved Developed Producing (PDP)
and Proved Developed Non-Producing (PDNP). Within
each reserve category section are grand total Table Is and
Table II summaries. The Table Is present composite
reserve estimates and economic forecasts for the particular
reserve category. Following Table I are two Table II
oneline summaries that present estimates of ultimate
recovery, gross and net reserves, ownership, revenue, expenses,
investments, net income and discounted cash flow
(DCF) for the individual properties that make up the
corresponding Table I. The first Table II is sorted
alphabetically by Lease Name, and the second Table II is
sorted on DCF by property.
For a more detailed description of the report layout, please
refer to the Table of Contents following this letter. The data
presented in each Table I is explained in page 1 of the
Appendix. The methods employed in estimating reserves are
described in page 2 of the Appendix.
Hydrocarbon
Pricing
As provided, oil and gas prices were adjusted to the following
index prices:
|
|
|
|
|
|
|
|
|
|
|
WTI Cushing
|
|
Henry Hub
|
|
|
Crude Oil
|
|
Natural Gas
|
Year
|
|
$/STB
|
|
$/MMBTU
|
|
2009
|
|
|
61.18
|
|
|
|
3.833
|
|
Thereafter
|
|
|
61.18
|
|
|
|
3.833
|
|
As specified by the SEC, the above prices are
12-month
averages based upon the price on the first day of each month
during 2009. Adjustments to oil and gas prices were made based
upon data provided by your office. These adjustments include
treating cost, transportation charges
and/or crude
quality and gravity corrections. Gas prices were further
adjusted with a heating value (BTU content) applied on a
per-property basis.
Expenses
and Taxes
Lease operating expenses and overhead expenses were provided by
you and were accepted as furnished. As requested, expenses and
investments were not escalated. In the attached tables, lease
operating expenses are presented in column 22 and overhead
charges are presented in column 26.
Severance tax rates were applied as directed. For Kansas
properties, severance taxes were applied at 4.33 percent of
revenue until exemption levels were forecasted to be reached.
The severance tax rate was dropped to zero when a rate of
6 barrels/day per oil well was reached, or when gross gas
production value reached $87/day per gas well. Severance taxes
were forecasted at 4.6 percent of oil revenue and
7.5 percent of gas revenue for properties in Texas. Ad
Valorem taxes for Kansas properties were applied at
6 percent of revenue, but dropped to 1 percent as
properties qualified for the severance tax exemption. Kansas oil
and gas conservation taxes were included within the ad valorem
tax estimates. Ad valorem taxes were applied at 2% of revenue
for Texas properties.
Annex A-5
VOC Kansas
Energy Partners, LLC
October 20, 2010
MISCELLANEOUS
An on-site
field inspection of the properties has not been performed nor
has the mechanical operation or condition of the wells and their
related facilities been examined, nor have the wells been tested
by Cawley, Gillespie & Associates, Inc. Possible
environmental liability related to the properties has not been
investigated nor considered. The cost of plugging and the
salvage value of equipment at abandonment have not been included
except as noted above.
The proved reserve classifications used herein conform to the
criteria of the Securities and Exchange Commission as defined in
page 3 of the Appendix. The reserves and economics are
predicated on regulatory agency classifications, rules,
policies, laws, taxes and royalties in effect on the effective
date, except as noted herein. The possible effects of changes in
legislation or other Federal or State restrictive actions have
not been considered. All reserve estimates represent our best
judgment based on data available at the time of preparation, and
assumptions as to future economic and regulatory conditions. It
should be realized that the reserves actually recovered, the
revenue derived therefrom and the actual cost incurred could be
more or less than the estimated amounts
The reserve estimates and forecasts were based upon
interpretations of factual data furnished by your office.
Production data, ownership information, price differentials,
expense data and tax details were furnished by Vess Oil
Corporation, and were accepted as furnished. To some extent,
information from public records was used to check
and/or
supplement these data. The basic engineering and geological data
were utilized subject to third party reservations and
qualifications. Nothing has come to our attention, however, that
would cause us to believe that we are not justified in relying
on such data.
This report was prepared for the exclusive use of Vess Oil
Corporation. Third parties should not rely on it without the
written consent of the above and Cawley, Gillespie &
Associates, Inc. We are independent registered professional
engineers and geologists. We do not own an interest in the
properties, VOC-KEP or Vess Oil Corporation and are not employed
on a contingent basis. Our work papers and related data are
available for inspection and review by authorized, interested
parties.
Yours very truly,
/s/ Cawley,
Gillespie & Associates, Inc.
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm (F-693)
Annex A-6
Trust Units
VOC ENERGY TRUST
PROSPECTUS
RAYMOND JAMES
,
2011
PART II
INFORMATION
NOT REQUIRED IN 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 Securities and Exchange
Commission registration fee, the FINRA filing and the NYSE
listing fee, the amounts set forth below are estimates.
|
|
|
|
|
Registration fee
|
|
$
|
23,220
|
|
FINRA filing fee
|
|
|
20,500
|
|
NYSE listing fee
|
|
|
*
|
|
Printing and engraving expenses
|
|
|
*
|
|
Fees and expenses of legal counsel
|
|
|
*
|
|
Accounting fees and expenses
|
|
|
*
|
|
Transfer agent and registrar fees
|
|
|
*
|
|
Trustee fees and expenses
|
|
|
*
|
|
Miscellaneous
|
|
|
*
|
|
|
|
|
|
|
Total
|
|
$
|
*
|
|
|
|
|
|
|
|
|
|
* |
|
To be provided by amendment |
|
|
Item 14.
|
Indemnification
of Directors and Officers.
|
The trust agreement provides that the trustee and its officers,
agents and employees shall be indemnified from the assets of the
trust against and from any and all liabilities, expenses,
claims, damages or loss incurred by it individually or as
trustee in the administration of the trust and the trust assets,
including, without limitation, any liability, expenses, claims,
damages or loss arising out of or in connection with any
liability under environmental laws, or in the doing of any act
done or performed or omission occurring on account of it being
trustee or acting in such capacity, except such liability,
expense, claims, damages or loss as to which it is liable under
the trust agreement. In this regard, the trustee shall be liable
only for its own fraud or gross negligence or for acts or
omissions in bad faith and shall not be liable for any act or
omission of any agent or employee unless the trustee has acted
in bad faith or with gross negligence in the selection and
retention of such agent or employee. The trustee is entitled to
indemnification from the assets of the trust and shall have a
lien on the assets of the trust to secure it for the foregoing
indemnification.
Reference is made to the Underwriting Agreement to be filed as
an exhibit to this registration statement in which VOC Sponsor
and its affiliates will agree to indemnify the underwriters
against certain liabilities, including liabilities under the
Securities Act and to contribute to payments that may be
required to be made in respect of these liabilities. Subject to
any terms, conditions or restrictions set forth in the
partnership agreement, Chapter 8 of the Texas Business
Organizations Code empowers a Texas limited partnership to
indemnify and hold harmless any limited partnership or other
persons from and against all claims and demands whatsoever.
In connection with the preparation and filing of any shelf
registration statement, VOC Brazos will indemnify VOC Energy
Trust and certain of its affiliates from and against any
liabilities
II-1
under the Securities Act or any state securities laws arising
from the registration statement or prospectus. VOC Brazos will
bear all costs and expenses incidental to any shelf registration
statement, excluding any underwriting discounts and fees.
|
|
Item 15.
|
Recent
Sales of Unregistered Securities.
|
None.
|
|
Item 16.
|
Exhibits
and Financial Statement Schedules.
|
(a) Exhibits.
The following documents are filed as exhibits to this
registration statement:
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
1
|
.1
|
|
|
|
Form of Underwriting Agreement.
|
|
2
|
.1*
|
|
|
|
Contribution and Exchange Agreement among VOC Brazos Energy
Partners, L.P., VOC Kansas Energy Partners, LLC, VAP-III,
LLC, Vess Texas Acquisition Group, LLC, Vess Texas Partners,
LLC, and the other parties named therein.
|
|
3
|
.1*
|
|
|
|
Certificate of Limited Partnership of VOC Brazos Energy
Partners, L.P.
|
|
3
|
.2*
|
|
|
|
Amended and Restated Agreement of Limited Partnership of VOC
Brazos Energy Partners, L.P. dated as of September 21, 2009.
|
|
3
|
.3
|
|
|
|
Form of First Amendment to Amended and Restated Agreement of
Limited Partnership of VOC Brazos Energy Partners, L.P.
|
|
3
|
.4*
|
|
|
|
Certificate of Trust of VOC Energy Trust.
|
|
3
|
.5*
|
|
|
|
Trust Agreement dated November 3, 2010 among VOC
Brazos Energy Partners, L.P., as trustor, and Wilmington
Trust Company, and The Bank of New York Mellon
Trust Company, N.A., as trustees.
|
|
3
|
.6
|
|
|
|
Form of Amended and Restated Trust Agreement.
|
|
5
|
.1
|
|
|
|
Opinion of Morris James LLP relating to the validity of the
trust units.
|
|
8
|
.1
|
|
|
|
Opinion of Vinson & Elkins L.L.P. relating to tax
matters.
|
|
10
|
.1*
|
|
|
|
Credit Agreement dated as of June 27, 2008 among VOC Brazos
Energy Partners, L.P., as borrower, Bank of America, N.A., as
lender, and the other parties named therein.
|
|
10
|
.2*
|
|
|
|
First Amendment to Credit Agreement dated August 12, 2008
by and among VOC Brazos, LP (now VOC Brazos, LLC), as borrower,
Bank of America, N.A. and the other parties named therein.
|
|
10
|
.3
|
|
|
|
Form of Term Net Profits Interest Conveyance.
|
|
10
|
.4
|
|
|
|
Form of Administrative Services Agreement.
|
|
10
|
.5
|
|
|
|
Form of Registration Rights Agreement.
|
|
21
|
.1*
|
|
|
|
Subsidiaries of VOC Brazos Energy Partners, L.P.
|
|
23
|
.1*
|
|
|
|
Consent of Grant Thornton LLP.
|
|
23
|
.2
|
|
|
|
Consent of Morris James LLP (contained in Exhibit 5.1).
|
|
23
|
.3
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|
|
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Consent of Vinson & Elkins L.L.P. (contained in
Exhibit 8.1).
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23
|
.4*
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|
|
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Consent of Cawley, Gillespie & Associates, Inc.
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|
99
|
.1*
|
|
|
|
Summary Reserve Reports of Cawley, Gillespie &
Associates, Inc. (included as Annex A to the prospectus)
|
(b) Financial Statement Schedules.
II-2
No financial statement schedules are required to be included
herewith or they have been omitted because the information
required to be set forth therein is not applicable.
The undersigned registrants hereby undertake:
(a) Insofar as indemnification for liabilities arising
under the Securities Act of 1933 may be permitted to
directors, officers and controlling persons of the registrants
pursuant to the provisions described in Item 14, or
otherwise, the registrants have been advised that in the opinion
of the SEC such indemnification is against public policy as
expressed in the Securities Act of 1933 and is, therefore,
unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the
registrants of expenses incurred or paid by a director, officer
or controlling person of the registrants in the successful
defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the
securities being registered, the registrants will, unless in the
opinion of their respective counsel the matter has been settled
by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by them
is against public policy as expressed in the Securities Act of
1933 and will be governed by the final adjudication of such
issue.
(b) 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.
(c) For purpose of determining any liability under the
Securities Act of 1933, the information omitted from the form of
prospectus filed as part of this Registration Statement in
reliance upon Rule 430A and contained in the form of
prospectus filed by the registrants 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.
(d) For the purpose of determining any liability under the
Securities Act of 1933, 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.
(e) To send to each trust unitholder at least on an annual
basis a detailed statement of any transactions with the trustees
or their respective affiliates, and of fees, commissions,
compensation and other benefits paid, or accrued to the trustees
or their respective affiliates for the fiscal year completed,
showing the amount paid or accrued to each recipient and the
services performed.
(f) To provide to the trust unitholders the financial
statements required by
Form 10-K
for the first full fiscal year of operations of the trust.
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 Wichita, State of
Kansas, on December 29, 2010.
VOC Brazos Energy Partners, L.P.
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|
|
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By:
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Vess Texas Partners, LLC,
its General Partner
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|
|
By:
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Vess Holding Corporation,
its Manager
|
Name: J. Michael Vess
Title: Designated Representative
II-4
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 Wichita, State of
Kansas, on December 29, 2010.
VOC Energy Trust
|
|
|
|
By:
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VOC Brazos Energy Partners, L.P.
|
|
|
By:
|
Vess Texas Partners, LLC,
its General Partner
|
|
|
By:
|
Vess Holding Corporation,
its Manager
|
Name: J. Michael Vess
Title: Designated Representative
II-5
INDEX TO
EXHIBITS
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|
|
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|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
1
|
.1
|
|
|
|
Form of Underwriting Agreement.
|
|
2
|
.1*
|
|
|
|
Contribution and Exchange Agreement among VOC Brazos Energy
Partners, L.P., VOC Kansas Energy Partners, LLC, VAP-III,
LLC, Vess Texas Acquisition Group, LLC, Vess Texas Partners,
LLC, and the other parties named therein.
|
|
3
|
.1*
|
|
|
|
Certificate of Limited Partnership of VOC Brazos Energy
Partners, L.P.
|
|
3
|
.2*
|
|
|
|
Amended and Restated Agreement of Limited Partnership of VOC
Brazos Energy Partners, L.P. dated as of September 21, 2009.
|
|
3
|
.3
|
|
|
|
Form of First Amendment to Amended and Restated Agreement of
Limited Partnership of VOC Brazos Energy Partners, L.P.
|
|
3
|
.4*
|
|
|
|
Certificate of Trust of VOC Energy Trust.
|
|
3
|
.5*
|
|
|
|
Trust Agreement dated November 3, 2010 among VOC
Brazos Energy Partners, L.P., as trustor, and Wilmington
Trust Company, and The Bank of New York Mellon
Trust Company, N.A., as trustees.
|
|
3
|
.6
|
|
|
|
Form of Amended and Restated Trust Agreement.
|
|
5
|
.1
|
|
|
|
Opinion of Morris James LLP relating to the validity of the
trust units.
|
|
8
|
.1
|
|
|
|
Opinion of Vinson & Elkins L.L.P. relating to tax
matters.
|
|
10
|
.1*
|
|
|
|
Credit Agreement dated as of June 27, 2008 among VOC Brazos
Energy Partners L.P., as borrower, Bank of America, N.A., as
lender, and the other parties named therein.
|
|
10
|
.2*
|
|
|
|
First Amendment to Credit Agreement dated August 12, 2008
by and among VOC Brazos, LP (now VOC Brazos, LLC), as borrower,
Bank of America, N.A. and the other parties named therein.
|
|
10
|
.3
|
|
|
|
Form of Term Net Profits Interest Conveyance.
|
|
10
|
.4
|
|
|
|
Form of Administrative Services Agreement.
|
|
10
|
.5
|
|
|
|
Form of Registration Rights Agreement.
|
|
21
|
.1*
|
|
|
|
Subsidiaries of VOC Brazos Energy Partners, L.P.
|
|
23
|
.1*
|
|
|
|
Consent of Grant Thornton LLP.
|
|
23
|
.2
|
|
|
|
Consent of Morris James LLP (contained in Exhibit 5.1).
|
|
23
|
.3
|
|
|
|
Consent of Vinson & Elkins L.L.P. (contained in
Exhibit 8.1).
|
|
23
|
.4*
|
|
|
|
Consent of Cawley, Gillespie & Associates, Inc.
|
|
99
|
.1*
|
|
|
|
Summary Reserve Reports of Cawley, Gillespie &
Associates, Inc. (included as Annex A to the prospectus).
|