UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
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SECURITIES EXCHANGE ACT OF 1934
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For the fiscal
year ended December 31, 2010
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or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE
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SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number:
001-33631
CRESTWOOD MIDSTREAM PARTNERS
LP
(Exact name of registrant as
specified in its charter)
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Delaware
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56-2639586
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer Identification No.)
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717 Texas Avenue, Suite 3150, Houston, Texas
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77002
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(Address of principal executive offices)
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(Zip Code)
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(832) 519-2200
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the
Act:
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Title of each class
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Name of each exchange on which registered
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Common Units of Limited Partner Interests
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NYSE
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Securities registered pursuant to Section 12(g) of the
Act: None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Exchange
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes o No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein, and will not be contained, to the best
of registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. 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 þ
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Non-accelerated
filer o
(Do not check if a smaller
reporting company)
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Smaller Reporting
company o
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
As of June 30, 2010, the aggregate market value of the
registrants common units held by non-affiliates of the
registrant was approximately $219,284,367 based on the closing
sale price of $19.42 as reported on the NYSE.
As of February 14, 2011, the registrant has 31,187,696
common units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
DEFINITIONS
As used in this annual report unless the context requires
otherwise:
Alliance Midstream Assets means
gathering and treating assets purchased from Quicksilver in
January 2010 in the Alliance Airport area of Tarrant and Denton
Counties, Texas
Alliance System means the Alliance
Midstream Assets and subsequent additions
Bbl or Bbls
means barrel or barrels
Bbld means barrel or barrels per day
Btu means British Thermal units, a
measure of heating value
CMLP means Crestwood Midstream
Partners LP and our wholly owned subsidiaries, formerly known as
Quicksilver Gas Services LP (KGS), which now trades under the
ticker symbol CMLP
Credit Facility means, prior to
October 1, 2010, our senior secured credit facility, as
amended, dated August 10, 2007; and effective
October 1, 2010, means our new senior secured credit
facility filed as Exhibit 10.6 and included herein
Crestwood means Crestwood Holdings
Partners, LLC and its affiliates
Crestwood Counties means Hood,
Somervell, Johnson, Tarrant, Hill, Parker and Bosque and Erath
Counties in Texas
Crestwood Holdings means Crestwood
Holdings LLC and its affiliates
Crestwood Transaction means the sale
to Crestwood by Quicksilver of all its interests in CMLP that
completed on October 1, 2010
DOT means the U.S. Department of
Transportation
EBITDA means earnings before interest,
taxes, depreciation and accretion
EPA means the U.S. Environmental
Protection Agency
Exchange Act means the Securities
Exchange Act of 1934, as amended
FASB means the Financial Accounting
Standards Board, which promulgates accounting standards
FASC means the FASB Accounting
Standards Codification
FERC means the Federal Energy
Regulatory Commission
First Reserve means First Reserve
Management, LP and certain of its affiliates
GAAP means generally accepted
accounting principles in the U.S.
General Partner means Crestwood Gas
Services GP LLC, formerly known as Quicksilver Gas Services GP
LLC
HCDS means Hill County Dry System
IPO means our initial public offering
completed on August 10, 2007
KGS means Quicksilver Gas Services
L.P. (now known as CMLP or Crestwood Midstream Partners LP) and
its wholly owned subsidiaries
LADS means Lake Arlington Dry System
LIBOR means London Interbank Offered
Rate
Management means management of
Crestwood Midstream Partners LPs General Partner
MMBtu means million Btu
Mcf means thousand cubic feet
MMcf means million cubic feet
MMcfd means million cubic feet per day
NGL or NGLs
means natural gas liquids
NYSE means the New York Stock Exchange
Oil includes crude oil and condensate
Omnibus Agreement means the Omnibus
Agreement, dated October 8, 2010, among our General Partner
and Crestwood
OSHA means Occupational Safety and
Health Administration
Partnership Agreement means the Second
Amended and Restated Agreement of Limited Partnership of
Quicksilver Gas Services LP, dated February 19, 2008, as
amended
Predecessor means prior to our IPO,
collectively Cowtown Pipeline L.P., Cowtown Pipeline Partners
L.P., Cowtown Gas Processing L.P., and Cowtown Gas Processing
Partners L.P.
Quicksilver means Quicksilver
Resources Inc. and its wholly owned subsidiaries
Quicksilver Counties means Hood,
Somervell, Johnson, Tarrant, Hill, Parker, Bosque and Erath
Counties in Texas where Quicksilver conducts the majority of its
U.S. operations
Repurchase Obligation Waiver means the
waiver, dated November 2009, in which we and Quicksilver
mutually agreed to waive all rights and obligations to transfer
ownership of HCDS to KGS.
SEC means the U.S. Securities and
Exchange Commission
Tcfe means trillion cubic feet of
natural gas equivalents
TRRC means Texas Railroad Commission
2007 Equity Plan means the Crestwood
Midstream Partners, LP Third Amended and Restated 2007 Equity
Plan
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INDEX TO
ANNUAL REPORT ON
FORM 10-K
For the Year Ended December 31, 2010
Except as otherwise specified and unless the context otherwise
requires, references to the Company, Crestwood
Midstream, CMLP, we,
us, and our refer to Crestwood Midstream
Partners LP and its consolidated subsidiaries.
Crestwood refers to Crestwood Holdings Partners, LLC
and its consolidated subsidiaries, excluding CMLP and Crestwood
Gas Services GP LLC, our General Partner.
3
FORWARD-LOOKING
INFORMATION
Certain statements contained in this report and other materials
we file with the SEC, or in other written or oral statements
made or to be made by us, other than statements of historical
fact, are forward-looking statements as defined in
the Private Securities Litigation Reform Act of 1995.
Forward-looking statements reflect our current expectations or
forecasts of future events. Words such as may,
assume, forecast, predict,
strategy, expect, intend,
plan, aim, estimate,
anticipate, believe,
project, budget, potential,
or continue, and similar expressions are used to
identify forward-looking statements. Forward-looking statements
can be affected by assumptions used or by known or unknown risks
or uncertainties. Consequently, no forward-looking statements
can be guaranteed. Actual results may vary materially. You are
cautioned not to place undue reliance on any forward-looking
statements and should also understand that it is not possible to
predict or identify all such factors and should not consider the
following list to be a complete statement of all potential risks
and uncertainties. Factors that could cause our actual results
to differ materially from the results contemplated by such
forward-looking statements include:
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changes in general economic conditions;
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fluctuations in natural gas prices;
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failure or delays by our customers in achieving expected
production from natural gas projects;
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competitive conditions in our industry;
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actions taken or non-performance by third parties, including
suppliers, contractors, operators, processors, transporters and
customers;
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fluctuations in the value of certain of our assets and
liabilities;
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changes in the availability and cost of capital;
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operating hazards, natural disasters, weather-related delays,
casualty losses and other matters beyond our control;
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construction costs or capital expenditures exceeding estimated
or budgeted amounts;
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the effects of existing and future laws and governmental
regulations, including environmental and climate change
requirements;
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the effects of existing or future litigation; and
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certain factors discussed elsewhere in this annual report.
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In addition, there are significant risks and uncertainties
relating to our pending acquisition of the midstream assets in
the Fayetteville Shale and Granite Wash plays from Frontier Gas
Services, LLC (Frontier) and, if we acquire those
assets, our ownership of such assets, including
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the acquisition may not be consummated;
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the representations, warranties, and indemnifications by
Frontier are limited in the acquisition agreement and our
diligence into the business has been limited; as a result, the
assumptions on which our estimates of future results of the
business have been based may prove to be incorrect in a number
of material ways, resulting in our not realizing the expected
benefits of the acquisition and our having limited recourse
against Frontier;
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financing the acquisition will substantially increase our
leverage;
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we may not be able to obtain debt financing for the acquisition
on expected or acceptable terms, which would require us to draw
on the committed bridge and make the acquisition less accretive;
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the closing of the acquisition is not subject to a financing
condition and our bridge does not backstop the equity portion of
our purchase price or our equity commitments, which means we may
be obligated to close the acquisition even if we do not have
sufficient funds available to pay the purchase price;
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the acquisition could expose us to additional unknown and
contingent liabilities;
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we may not be able to successfully integrate the business, or
our cost savings and other synergies from the transaction may
not be fully realized or may take longer to realize than
expected; and
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we may experience disruption from the transaction making it more
difficult to maintain relationships with customers, employees or
suppliers.
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The list of factors is not exhaustive, and new factors may
emerge or changes to these factors may occur that would impact
our business. Additional information regarding these and other
factors may be contained in our filings with the SEC, especially
on
Forms 10-K,
10-Q and
8-K. All
such risk factors are difficult to predict and are subject to
material uncertainties that may affect actual results and may be
beyond our control. The forward-looking statements included in
this report are made only as of the date of this report, and we
undertake no obligation to update any of these forward-looking
statements to reflect subsequent events or circumstances except
to the extent required by applicable law.
All forward-looking statements are expressly qualified in their
entirety by the foregoing cautionary statements.
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PART I
General
Overview
Crestwood Midstream Partners LP is a growth-oriented Delaware
master limited partnership, or MLP, organized in
2007 to own, operate, acquire and develop midstream energy
assets. Our common units are publicly-traded and listed on the
NYSE under the symbol CMLP. Our General Partner is
owned by Crestwood. First Reserve, a private equity firm with
substantial investments in the energy industry, owns a
significant equity interest in Crestwood. We are managed by our
General Partner and conduct substantially all of our business
through CMLP. Our principal executive offices are located at 717
Texas Avenue, Suite 3150, Houston, Texas 77002, our
telephone number is
832-519-2200
and our website address is www.crestwoodlp.com.
With midstream assets in the Fort Worth Basin located in
North Texas, we are engaged in the business of gathering,
compressing, treating, processing and transporting natural gas.
The Fort Worth Basin, which includes the Barnett Shale
formation, is a proven crude oil and natural gas producing basin
where drilling for crude oil began in 1912. A new fracturing
technique which was introduced in the 1990s, and combined
with other advances in drilling and completion techniques,
contributed to a significant increase in investment in and
production from the basin over the past decade. We believe that
these improved drilling and production techniques have made it
one of the most important natural gas producing areas in the
United States.
For the year ended December 31, 2010, all of our services
are provided under long-term contracts with fee-based rates. A
substantial part of our business is conducted with Quicksilver
and governed by contracts which were entered into during 2007.
The initial term of these contracts extend through 2020. Over
90% of our total natural gas gathering, processing and
transportation throughput was comprised of natural gas
production owned or controlled by Quicksilver during the year
ended December 31, 2010. Approximately 11% of our gathered
volumes are comprised of natural gas purchased by Quicksilver
from Eni SpA and gathered under Quicksilvers Alliance
gathering agreement. Quicksilver has contractually dedicated to
us all of the natural gas production it owns or controls from
the wells that are currently connected to our gathering systems,
as well as natural gas produced from future wells that are
drilled within certain Quicksilver Counties. As a result, we
expect this dedication will continue to expand as additional
wells are connected to these gathering systems.
Crestwood
Transaction
Transaction. On October 1, 2010, the
Crestwood Transaction closed and Quicksilver sold all of its
ownership interests in Crestwood Midstream Partners LP to
Crestwood. The Crestwood Transaction included:
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Crestwoods purchase of a 100% interest in Crestwood Gas
Services GP LLC, our General Partner
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5,696,752 common units and 11,513,625 subordinated
units; and
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$58 million subordinated note payable by Crestwood
Midstream Partners LP.
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Quicksilver received from Crestwood $701 million cash and
has the right to receive additional cash payments from Crestwood
in 2012 and 2013 of up to $72 million in the aggregate. The
additional payments will be determined by an earn-out formula
which is based upon our actual gathering volumes during 2011 and
2012, and if earned would be an obligation of Crestwood and not
an obligation of Crestwood Midstream Partners LP. The earn-out
provision was designed to provide additional incentive for our
largest customer, Quicksilver, to maximize volumes through our
pipeline systems and processing facilities.
Name and Ticker Symbol Change. On
October 4, 2010, our name changed from Quicksilver Gas
Services LP to Crestwood Midstream Partners LP and our ticker
symbol on the NYSE for our publicly traded common units changed
from KGS to CMLP.
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The Crestwood Transaction did not have any direct impact to our
historical financial statements as previously reported. However,
during October 2010, the following significant matters occurred:
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recognition of approximately $3.6 million of costs
associated with the vesting of equity-based compensation of our
phantom units in accordance with the
change-in-control
provisions of our 2007 Equity Plan;
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acceleration of amounts due under our old $320 million
credit facility, which was replaced with a new $400 million
Credit Facility;
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termination of our omnibus agreement with Quicksilver, which was
replaced with a new Omnibus Agreement;
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termination of our Services and Secondment Agreement with
Quicksilver which we replaced with a Transition Services
Agreement with Quicksilver;
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extension of the tenor of all of our gathering and processing
agreements with Quicksilver to 2020; and
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change to a fixed gathering rate of $0.55 per Mcf for the
Alliance System for Quicksilver to replace the variable rate
which had a range of $0.40 to $0.55 per Mcf.
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Subordinated Units Termination. Under the
terms of our partnership agreement and upon the payment of our
quarterly cash distribution to unitholders on November 12,
2010, our subordination period ended. As a result, our
11,513,625 subordinated units held by Crestwood converted into
common units on a one for one basis on November 15, 2010.
The conversion of the subordinated units did not impact the
amount of cash distributions paid. The conversion had no impact
on our calculation of net income per limited partner unit since
the subordinated units were previously included in our
historical net income per limited partner unit calculation.
Subordinated Note Conversion. On
October 18, 2010, our Subordinated Note payable to
Crestwood was converted into common units, based upon the
average closing common unit price for a 20
trading-day
period that ended October 15, 2010. The conversion of the
Subordinated Note was unanimously approved by the conflicts
committee of our General Partners board of directors and
resulted in the issuance of 2,333,712 of our common units in
exchange for the outstanding balance of the Subordinated Note at
the time of conversion.
Credit Agreement. On October 1, 2010, we
entered into a new $400 million five-year senior secured
revolving credit facility, which can be expanded to a maximum of
$500 million. This revolving credit facility matures on
October 1, 2015 and bears interest at the applicable LIBOR
plus applicable margins of 2.75%. The new Credit Facility is
secured by substantially all of CMLPs and its
subsidiaries assets and is guaranteed by CMLPs
subsidiaries.
As of December 31, 2010 our ownership is as follows:
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Ownership Percentage
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Crestwood
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Public
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Total
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General partner interest
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1.5
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%
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1.5
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%
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Limited partner interest:
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Common unitholders
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61.7
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%
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36.8
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%
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98.5
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%
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Total interests
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63.2
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%
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36.8
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%
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100.0
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%
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Recent
Events
On February 18, 2011, we entered into a Purchase and Sale
Agreement (the Frontier Purchase and Sale Agreement)
with Frontier Gas Services, LLC, a Delaware limited liability
company (Frontier), pursuant to which we agreed to
acquire midstream assets (the Frontier Assets) in
the Fayetteville Shale and the Granite Wash plays for a purchase
price of approximately $338 million, with an additional
$15 million to be paid to Frontier if certain operational
objectives are met within six-months of the closing date (the
Frontier Acquisition). The final purchase price is
payable in cash, and we expect to finance the purchase through a
combination of equity and debt as described below. Consummation
of the Frontier Acquisition is subject to customary closing
conditions and
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regulatory approval. There can be no assurance that these
closing conditions will be satisfied. We expect to close the
Frontier Acquisition in the second quarter of 2011.
On February 18, 2011, we entered into a Class C Unit
Purchase Agreement (the Class C Unit Purchase
Agreement) with the purchasers named therein (the
Class C Unit Purchasers) to sell approximately
6.2 million Class C Units in a private placement. The
negotiated purchase price for the Class C Units is $24.50
per unit, resulting in gross proceeds to us of approximately
$153 million. If the closing of the private placement is
after the record date for our first quarter 2011 distribution in
respect of our Common Units, the price per Class C Unit
will be reduced by such distribution, but the total purchase
price will remain $153 million, and the number of
Class C Units issued will be increased accordingly. We
intend to use the net proceeds from the private placement to
fund a portion of the purchase price for the Frontier
Acquisition. The private placement of the Class C Units
pursuant to the Class C Unit Purchase Agreement is being
made in reliance upon an exemption from the registration
requirements of the Securities Act pursuant to Section 4(2)
and Regulation D thereof. The closing of the private
placement is subject to certain conditions including
(i) the closing of the Frontier Acquisition, (ii) the
receipt of, or binding commitments to fund the Frontier
Acquisition through (A) equity proceeds of not less than
$150 million pursuant to the Class C Unit Purchase
Agreement, and (B) debt financing of not less than
$185 million from the issuance or incurrence of
(x) borrowings under our Credit Facility,
(y) borrowings under a bridge facility,
and/or
(z) senior unsecured notes, senior subordinated notes
and/or other
debt securities, with the weighted average total effective yield
for the aggregate of all debt in this item (ii)(B) to be no more
than 8.75%, (iii) the adoption of an amendment to our
Partnership Agreement to establish the terms of the Class C
Units, (iv) NYSE approval for listing of the Common Units
to be issued upon conversion of the Class C Units, and
(v) our filing of this annual report with the SEC.
In connection to the Class C Unit Purchase Agreement, we
have agreed to enter into a registration rights agreement with
the Class C Unit Purchasers (the Registration Rights
Agreement). Pursuant to the Registration Rights Agreement,
upon request of a Class C Unit holder, we will be required
to file a resale registration statement to register (i) the
Class C Units issued pursuant to the Class C Unit
Purchase Agreement, (ii) the Common Units issuable upon
conversion of the Class C Units issued, (iii) any
Class C Units issued in respect of the Class C Units
as a distribution in kind in lieu of cash distributions and
(iv) any Class C Units issued as liquidated damages
under the Registration Rights Agreement, as soon as practicable
after such request.
In connection with the proposed Frontier Acquisition, we
obtained a commitment from UBS Loan Finance LLC, UBS Securities
LLC, BNP Paribas, BNP Paribas Securities Corp., Royal Bank of
Canada, RBC Capital Markets, RBS Securities Inc. and the Royal
Bank of Scotland plc for senior unsecured bridge loans in an
aggregate amount up to $200 million (the Bridge
Loans). The commitment will expire upon the earliest to
occur of (i) the termination of the Frontier Purchase and
Sale Agreement in accordance with its own terms or
(ii) 90 days after February 18, 2011.
The foregoing description of the Frontier Purchase and Sale
Agreement and the Class C Unit Purchase Agreement is only a
summary, does not purport to be complete and is qualified in its
entirety by reference to the Frontier Purchase and Sale
Agreement and Class C Unit Purchase Agreement, which are
attached as Exhibit 2.3 and Exhibit 10.21,
respectively to this annual report on
Form 10-K
and are included herein by reference.
Business
Strategy
Our primary business objective is to increase the value of our
unitholders investment in us by increasing and expanding
our sources of fee-based cash flow which should lead to
increased distributable cash flow and distributions per unit. We
intend to achieve this objective by executing the following
business strategies:
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Pursuing midstream acquisitions. We intend to
pursue strategic midstream acquisition opportunities that would
diversify and extend our geographic, customer and business
profile and provide visible organic growth opportunities for us.
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Increasing utilization of existing assets and prudently
expanding our pipeline capacity to meet our customers
gathering, processing and treating
needs. Quicksilver, which has contractually
dedicated additional volumes to our systems, has publicly
announced a drilling program in the Fort Worth Basin for
2011 that we expect to result in increased volumes through our
assets. While it may be necessary for us to
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incur capital expenditures to accommodate these additional
volumes in certain areas, we expect that our budgeted capital
expenditures of $37 million for 2011, including both growth
capital and maintenance capital, will be adequate to meet these
needs.
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Attracting new customers and volumes to our existing
facilities. We believe that the Fort Worth
Basin will continue to be an area of significant capital
investment by energy companies. We aim to attract increased
gathering, processing and treating volumes by marketing our
midstream services, expanding our gathering system and providing
superior customer service to these natural gas producers.
Further, we believe that the high cost of entry into the
midstream business serves as a barrier to competitors entering
the market and enhances our ability to compete for third
parties volumes.
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Minimizing commodity price exposure and maintaining a
disciplined financial policy. Where possible, we
intend to continue to pursue fee-based service agreements which
allow us to minimize significant direct commodity price
exposure. We also intend to follow a disciplined financial
policy by maintaining a prudent cash distribution policy and
capital structure.
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Business
Strengths
We believe that we are well positioned to successfully execute
our primary business objective and business strategies due to
the following competitive strengths:
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Our assets are strategically located in the Fort Worth
Basin. The Fort Worth Basin remains one of
the most important natural gas producing areas in the United
States. We believe that our established position in this area,
together with anticipated growth in production from Quicksilver
and other producers, gives us an opportunity to expand our
gathering system footprint and increase our throughput volumes
and plant utilization, ultimately increasing cash flows.
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We provide an integrated package of midstream
services. We provide a broad range of bundled
midstream services to natural gas producers, including
gathering, compressing, treating and processing natural gas and
delivering NGLs.
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We have the financial flexibility to pursue growth
opportunities. At December 31, 2010, the
lenders commitments under our Credit Facility were
$400 million and could expand our borrowing capacity up to
$500 million, if certain financial ratios are achieved and
we seek and receive lender approval. Based on our results
through December 31, 2010, our total borrowing capacity was
$393 million and our borrowings were $283.5 million.
Our credit agreement matures on October 1, 2015. We believe
that the current and future capacity under the Credit Facility,
combined with internally generated funds and our ability to
access the capital markets, will enable us to complete all of
our near-term growth projects.
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We have an experienced, knowledgeable management team with a
proven record of performance. Our management team
has a proven record of enhancing value through the acquisition,
integration, development and operation of midstream assets in
our industry. We believe that this team provides us with a
strong foundation for developing additional natural gas
gathering and processing assets and pursuing strategic
acquisition opportunities.
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Acquisitions
We have made the following acquisition from Quicksilver:
Alliance Acquisition. On January 6, 2010,
we acquired certain midstream assets from an affiliate,
Quicksilver, consisting of a gathering system and a compression
facility with a total capacity of 115 MMcfd, an amine
treating facility with capacity of 180 MMcfd and a
dehydration treating facility with capacity of 200 MMcfd in
the Alliance Airport area of Tarrant and Denton Counties, Texas.
We refer to these assets collectively as the Alliance
Midstream Assets and the acquisition as the Alliance
Acquisition. This system gathers natural gas produced by
customers and delivers it to unaffiliated pipelines for further
transport downstream. The consideration we paid consisted of
$95.2 million in cash that was subsequently reduced to
$84.4 million due to a purchase price adjustment based on
the timing of construction costs of the system. The
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board of directors of our General Partner approved the Alliance
Acquisition, including the approval of the conflicts committee
of our General Partners board of directors.
Our
Assets and Areas of Operation
We conduct all of our operations in the midstream sector of the
energy industry with all of our operations conducted in the
Fort Worth Basin in Texas. Our operations are organized
into a single business segment which engages in gathering,
compressing, processing, treating and transporting natural gas
production in the United States.
As of December 31, 2010, we manage approximately
500 miles of natural gas gathering pipelines that range in
size from 4 to 20 inches in diameter. Our assets consist of
one natural gas treating facility, two gas processing
facilities, and one NGL pipeline. Our assets are all located in
the Fort Worth Basin in North Texas.
We conduct our operations through our Cowtown System, Lake
Arlington Dry System and Alliance Midstream Assets and formerly
Hill County Dry System as described below:
Cowtown
System
The Cowtown System located principally in Hood and Somervell
Counties in the southern portion of the Fort Worth Basin,
includes:
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the Cowtown Pipeline, consisting of a gathering system and
related gas compression facilities. This system gathers natural
gas produced by our customers and delivers it to the Cowtown and
Corvette Plants for processing;
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the Cowtown Plant, consisting of two natural gas processing
units with a total capacity of 200 MMcfd that extract NGLs
from the natural gas stream and deliver customers residue
gas and extracted NGLs to unaffiliated pipelines for sale
downstream; and
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the Corvette Plant, placed in service during 2009, consisting of
a 125 MMcfd natural gas processing unit that extracts NGLs
from the natural gas stream and delivers customers residue
gas and extracted NGLs to unaffiliated pipelines for sale
downstream.
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At the Cowtown and Corvette plants, our customers residue
gas is delivered to several large unaffiliated parties for
further transport downstream and their extracted NGLs are
delivered to two large unaffiliated pipelines through our NGL
pipeline. For 2010, the Cowtown and Corvette plants had a total
average throughput of 128 MMcfd of natural gas, resulting
in average NGL recovery of 16,754 Bbld.
Lake
Arlington Dry System
The LADS, located in eastern Tarrant County, consists of a gas
gathering system and related gas compression facility with
capacity of 230 MMcfd. This system gathers natural gas
produced by our customers and delivers it to unaffiliated
pipelines for sale downstream.
Alliance
Midstream Assets
During 2010, we completed the purchase of the Alliance Midstream
Assets from Quicksilver for a purchase price of
$84.4 million, which with subsequent additions we refer to
as the Alliance System. The Alliance System consists of a
gathering system and related compression facility with a
capacity of 300 MMcfd, an amine treating facility with
capacity of 360 MMcfd and a dehydration treating facility
with capacity of 300 MMcfd. This system gathers natural gas
produced by our customers and delivers it to unaffiliated
pipelines for sale downstream. The majority of the Alliance
Midstream Assets operations commenced service in September 2009,
although less significant operations had been conducted prior to
that time. Because the purchase of the Alliance Midstream Assets
was conducted among entities then under common control, GAAP
requires the inclusion of the Alliance Systems revenue and
expenses in our income statements for all periods presented,
including periods prior to our purchase of the system.
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Hill
County Dry System
As more fully described in Note 2 to our consolidated
financial statements, our financial information through November
2009 had included the operations of a gathering system in Hill
County, Texas. The HCDS gathers natural gas and delivers it to
unaffiliated pipelines for further transport and sale
downstream. As of November 2009, the revenue and expenses
directly attributable to the HCDS for the periods prior to
November 2009 have been retrospectively reported as discontinued
operations based upon the execution of the Repurchase Obligation
Waiver. The HCDS had previously been subject to a repurchase
obligation since its 2007 sale to Quicksilver. All repurchase
obligations to Quicksilver were concluded by December 31,
2009. Additionally, as a part of the Crestwood Transaction, we
have agreed to operate the HCDS on behalf of Quicksilver which
retained its ownership. We operate the HCDS pursuant to an
operating agreement between Quicksilver and us effective as of
the Crestwood Transaction.
Since our inception, we have made substantial capital
expenditures to increase our asset base in the Fort Worth
Basin. We anticipate that we will continue to make capital
expenditures as Quicksilver continues to develop its assets in
the Fort Worth Basin.
All of our pipelines are constructed on
rights-of-way
granted by the owners of the property. We have obtained, where
necessary, license or permit agreements from public authorities
and railroad companies to cross over or under, or to lay
facilities in or along, waterways, roads, railroad properties
and state highways, as applicable. In some cases, property on
which our pipeline was built was purchased in fee.
We believe that, subject to any encumbrances, we have
satisfactory title to our assets. We do not believe that any of
these encumbrances will materially reduce the value of our
properties or our interest in these properties or interfere with
their use in the operation of our business.
Competition
We have a dedication from Quicksilver for all of its natural gas
production from the Quicksilver Counties including all the areas
served by our Cowtown System, our LADS and for the areas served
by the Alliance Midstream Assets through 2020. We believe that
this dedication reduces the likelihood that a competitor could
effectively compete for Quicksilvers gathering and
processing business within the Quicksilver Counties.
If we expand our business in the future, either through organic
growth or acquisitions, we could face increased competition. We
anticipate that our primary competitors for unaffiliated volumes
in the Fort Worth Basin are Crosstex Energy LP, DCP
Midstream LLC and Energy Transfer Partners, L.P. We believe that
we are able to compete with these companies based on processing
efficiencies, operational costs, commercial terms offered to
producers and capital expenditures requirements, along with the
location and available capacity of our gathering systems and
processing plants.
Customers
and Concentration of Credit Risk
During 2010, Quicksilver accounted for more than 90% of our
revenues, making it the largest user of our service offerings.
No other customer contributed in excess of 10% of our revenues.
Quicksilver is an independent oil and natural gas company based
in Fort Worth, Texas with a considerable presence and
operating history in the Fort Worth Basin. As of
September 30, 2010, Quicksilver had drilled approximately
950 wells in the Fort Worth Basin, including
approximately 76 wells drilled during 2010. In addition,
Quicksilver holds approximately 163,000 net acres in the
Fort Worth Basin, with more than 10 years of drilling
inventory. Although Quicksilver continues to develop its
resources in the Quicksilver Counties, a downturn in their
future drilling program could reduce the volumes gathered,
treated and processed in our facilities if not replaced by other
producers in those areas. In addition, a default in
Quicksilvers payment to us for our services could have a
material impact in our cash flows.
Governmental
Regulation
Regulation of our business may affect certain aspects of our
operations and the market for our products and services. State
regulation of gathering facilities generally includes various
safety, environmental and, in some circumstances,
nondiscriminatory requirements, complaint-based rate regulation
or general utility regulation.
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We are subject to rate regulation, as implemented by the TRRC,
and have tariffs on file with them. Generally, the TRRC has the
authority to ensure that utility rates are just and reasonable
and not discriminatory. The rates we charge for intrastate
services are deemed just and reasonable unless otherwise
challenged. We cannot predict whether such a challenge will be
filed against us or whether the TRRC will change its regulation
of these rates. Failure to comply with the utilities regulations
can result in the imposition of administrative, civil and
criminal remedies. To date, there has been no adverse effect to
our system due to this regulation.
The TRRC also generally requires gatherers to perform services
without discrimination as to source of supply or producer. This
may restrict our ability to decide whose natural gas we gather.
Our assets include an intrastate common carrier NGL pipeline
subject to the regulation of the TRRC, which requires that our
NGL pipelines file tariff publications that contain all the
rules and regulations governing the rates and charges for
services we perform. NGL pipeline rates may be limited to
provide no more than a fair return on the aggregate value of the
pipeline property used to render services.
Gathering pipeline
regulation. Section 1(b) of the Natural Gas
Act, or NGA, exempts natural gas gathering
facilities from the jurisdiction of FERC. Our natural gas
gathering activity is not subject to Internet posting
requirements imposed by FERC as a result of FERCs market
transparency initiatives. We believe that our natural gas
pipelines meet the traditional tests that FERC has used to
determine that a pipeline is a gathering pipeline and is,
therefore, not subject to FERC jurisdiction. The distinction
between FERC-regulated transmission services and federally
unregulated gathering services, however, is the subject of
substantial, on-going litigation, so the classification and
regulation of our gathering facilities are subject to change
based on future determinations by FERC, the courts or Congress.
State regulation of gathering facilities generally includes
various safety, environmental and, in some circumstances,
nondiscriminatory take requirements and complaint-based rate
regulation. In recent years, FERC has taken a more light-handed
approach to regulation of the gathering activities of interstate
pipeline transmission companies, which has resulted in a number
of such companies transferring gathering facilities to
unregulated affiliates. As a result of these activities, natural
gas gathering may begin to receive greater regulatory scrutiny
at both the state and federal levels. Our natural gas gathering
operations could be adversely affected should they be subject to
more stringent application of state or federal regulation of
rates and services. Our natural gas gathering operations also
may be or become subject to additional safety and operational
regulations relating to the design, installation, testing,
construction, operation, replacement and management of gathering
facilities. Additional rules and legislation pertaining to these
matters are considered or adopted from time to time. We cannot
predict what effect, if any, such changes might have on our
operations, but the industry could be required to incur
additional capital expenditures and increased costs depending on
future legislative and regulatory changes.
Our natural gas gathering operations are subject to ratable take
and common purchaser statutes. These statutes generally require
our gathering pipelines to take natural gas without undue
discrimination as to source of supply or producer. These
statutes are designed to prohibit discrimination in favor of one
producer over another producer or one source of supply over
another source of supply. The regulations under these statutes
can have the effect of imposing some restrictions on our ability
as an owner of gathering facilities to decide with whom we
contract to gather natural gas. The state in which we operate
has adopted a complaint-based regulation of natural gas
gathering activities, which allows natural gas producers and
shippers to file complaints with state regulators in an effort
to resolve grievances relating to gathering access and rate
discrimination. We cannot predict whether such a complaint will
be filed against us in the future. Failure to comply with state
regulations can result in the imposition of administrative,
civil and criminal remedies. To date, there has been no adverse
effect to our systems due to these regulations.
Safety
and Maintenance Regulation
We are subject to regulation by the Pipeline and Hazardous
Materials Safety Administration, or PHMSA, of the
DOT pursuant to the Natural Gas Pipeline Safety Act of 1968, or
the NGPSA, and the Pipeline Safety Improvement Act
of 2002, or the PSIA, which was recently
reauthorized and amended by the Pipeline Inspection, Protection,
Enforcement and Safety Act of 2006. The NGPSA regulates safety
requirements in the design, construction, operation and
maintenance of gas pipeline facilities, while the PSIA
establishes mandatory inspections for all U.S. liquid and
gas transportation pipelines and some gathering lines in
high-population areas.
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The PHMSA has developed regulations implementing the PSIA that
require transportation pipeline operators to implement integrity
management programs, including more frequent inspections and
other measures to ensure pipeline safety in high
consequence areas, such as high population areas, areas
unusually sensitive to environmental damage and commercially
navigable waterways. We, or the entities in which we own an
interest, inspect our pipelines regularly in compliance with
state and federal maintenance requirements.
States are largely preempted by federal law from regulating
pipeline safety for interstate lines but most are certified by
the DOT to assume responsibility for enforcing federal
intrastate pipeline regulations and inspection of intrastate
pipelines. In practice, because states can adopt stricter
standards for intrastate pipelines than those imposed by the
federal government for interstate lines, states vary
considerably in their authority and capacity to address pipeline
safety. We do not anticipate any significant difficulty in
complying with applicable state laws and regulations. Our
pipelines have operations and maintenance plans designed to keep
the facilities in compliance with pipeline safety requirements.
In addition, we are subject to a number of federal and state
laws and regulations, including the OSHA and comparable state
statutes, the purposes of which are to protect the health and
safety of workers, both generally and within the pipeline
industry. In addition, the OSHA hazard communication standard,
the EPAs 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 our operations and that such
information be provided to employees, state and local government
authorities and citizens.
We and the entities in which we own an interest are also subject
to OSHA Process Safety Management regulations, as well as the
EPAs Risk Management Program, or RMP, which
are designed to prevent or minimize the consequences of
catastrophic releases of toxic, reactive, flammable or explosive
chemicals. These regulations apply to any process which involves
a chemical at or above specified thresholds or any process which
involves flammable liquid or gas in excess of 10,000 pounds. We
have an internal program of inspection designed to monitor and
enforce compliance with worker safety requirements. We believe
that we are in material compliance with all applicable laws and
regulations relating to worker health and safety.
Environmental
Matters
General. Our operation of pipelines, plants
and other facilities for the gathering, processing, compression,
treating and transporting of natural gas and other products is
subject to stringent and complex federal, state and local laws
and regulations relating to the protection of the environment.
As an owner or operator of these facilities, we must comply with
these laws and regulations at the federal, state and local
levels. These laws and regulations can restrict or impact our
business activities in many ways, such as:
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requiring the installation of pollution-control equipment or
otherwise restricting the way we can handle or dispose of our
wastes;
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limiting or prohibiting construction activities in sensitive
areas, such as wetlands, coastal regions or areas inhabited by
endangered or threatened species;
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requiring investigatory and remedial actions to mitigate or
eliminate pollution conditions caused by our operations or
attributable to former operations; and
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enjoining the operations of facilities deemed to be in
non-compliance with such environmental laws and regulations and
permits issued pursuant thereto.
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Failure to comply with these laws and regulations may trigger a
variety of administrative, civil and criminal enforcement
measures, including the assessment of monetary penalties, the
imposition of investigatory and remedial obligations and the
issuance of orders enjoining future operations or imposing
additional compliance requirements. Certain environmental
statutes impose strict, and in some cases, joint and several
liability for costs required to clean up and restore sites where
hazardous substances, hydrocarbons or wastes have been disposed
or otherwise released, thus, we may be subject to environmental
liability at our currently owned or operated facilities for
conditions caused prior to our involvement.
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The trend in environmental regulation is to place more
restrictions and limitations on activities that may affect the
environment, and thus, there can be no assurance as to the
amount or timing of future expenditures for environmental
compliance or remediation and actual future expenditures may be
different from the amounts we currently anticipate. We try to
anticipate future regulatory requirements that might be imposed
and plan accordingly to remain in compliance with changing
environmental laws and regulations and to minimize the costs of
such compliance. We also actively participate in industry groups
that help formulate recommendations for addressing existing or
future regulations.
We do not believe that compliance with current federal, state or
local environmental laws and regulations will have a material
adverse effect on our business, financial position or results of
operations or cash flows. In addition, we believe that the
various environmental activities in which we are presently
engaged are not expected to materially interrupt or diminish our
operational ability to gather, process, compress, treat and
transport natural gas. We can make no assurances, however, that
future events, such as changes in existing laws or enforcement
policies, the promulgation of new laws or regulations or the
development or discovery of new facts or conditions will not
cause us to incur significant costs. Below is a discussion of
several of the material environmental laws and regulations that
relate to our business. We believe that we are in material
compliance with applicable environmental laws and regulations.
Hazardous substances and waste. Our operations
are subject to environmental laws and regulations relating to
the management and release of hazardous substances, solid and
hazardous wastes and petroleum hydrocarbons. These laws
generally regulate the generation, storage, treatment,
transportation and disposal of solid and hazardous waste and may
impose strict, and in some cases, joint and several liability
for the investigation and remediation of affected areas where
hazardous substances may have been released or disposed. For
instance, the Comprehensive Environmental Response,
Compensation, and Liability Act, referred to as
CERCLA or 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. These persons include current owners or operators of
the site where a release of hazardous substances occurred, prior
owners or operators that owned or operated the site at the time
of the release, and companies that disposed or arranged for the
disposal of the hazardous substances found at the site. Under
CERCLA, these persons may be subject to strict and joint and
several 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 EPA and, in some instances,
third parties to act in response to threats to the public health
or the environment and to seek to recover the costs they incur
from the responsible classes of persons. It is not uncommon for
neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by
hazardous substances or other pollutants released into the
environment. Despite the petroleum exclusion of
CERCLA Section 101(14), which currently encompasses natural
gas, we may nonetheless handle hazardous substances within the
meaning of CERCLA, or similar state statutes, in the course of
our ordinary operations and, as a result, may be jointly and
severally liable under CERCLA for all or part of the costs
required to clean up sites at which these hazardous substances
have been released into the environment.
We also generate solid wastes, including hazardous wastes, which
are subject to the requirements of the Resource Conservation and
Recovery Act, or RCRA, and comparable state
statutes. While RCRA regulates both solid and hazardous wastes,
it imposes strict requirements on the generation, storage,
treatment, transportation and disposal of hazardous wastes.
Certain petroleum production wastes are excluded from
RCRAs hazardous waste regulations. However, it is possible
that these wastes, which could include wastes currently
generated during our operations, will in the future be
designated as hazardous wastes and, therefore, be
subject to more rigorous and costly disposal requirements. Any
such changes in the laws and regulations could have a material
adverse effect on our maintenance capital expenditures and
operating expenses.
We own or lease properties where hydrocarbons are being or have
been handled. We have generally utilized operating and disposal
practices that were standard in the industry at the time,
although hydrocarbons or other wastes may have been disposed of
or released on or under the properties owned or leased by us, or
on or under the other locations where these hydrocarbons and
wastes have been transported for treatment or disposal. In
addition, certain of these properties have been operated by
third parties whose treatment and disposal or release of
hydrocarbons and other wastes was not under our control. These
properties and the wastes disposed thereon
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may be subject to CERCLA, RCRA and analogous state laws. Under
these laws, we could be required to remove or remediate
previously disposed wastes (including wastes disposed of or
released by prior owners or operators), to clean up contaminated
property (including contaminated groundwater) or to perform
remedial operations to prevent future contamination. We are not
currently aware of any facts, events or conditions relating to
such requirements that could materially impact our financial
condition, results of operations or cash flows.
Air emissions. Our operations are subject to
the Federal Clean Air Act, or the CAA, and
comparable state laws and regulations. These laws and
regulations regulate emissions of air pollutants from various
industrial sources, including our compressor stations, and also
impose various monitoring and reporting requirements. Such laws
and regulations may require that we obtain pre-approval for the
construction or modification of certain projects or facilities,
obtain and strictly comply with air permits containing various
emissions and operational limitations and utilize specific
emission control technologies to limit emissions. Our failure to
comply with these requirements could subject us to monetary
penalties, injunctions, conditions or restrictions on operations
and, potentially, criminal enforcement actions. We believe that
we are in material compliance with these requirements. We may be
required to incur certain capital expenditures in the future for
air pollution control equipment in connection with obtaining and
maintaining permits and approvals for air emissions. We believe,
however, that our operations will not be materially adversely
affected by such requirements, and the requirements are not
expected to be any more burdensome to us than to any other
similarly situated company.
Climate change. In June 2009, the
U.S. House of Representatives passed the American Clean
Energy and Security Act of 2009. A similar bill introduced in
the Senate, the Clean Energy Jobs and American Power Act, did
not pass. Although the bills contained several differences, both
contained the basic feature of establishing a cap and
trade system for restricting greenhouse gas emissions in
the U.S. Under such system, certain sources of greenhouse
gas emissions would be required to obtain greenhouse gas
emission allowances corresponding to their annual
emissions of greenhouse gases. The number of emission allowances
issued each year would decline as necessary to meet overall
emission reduction goals. As the number of greenhouse gas
emission allowances declines each year, the cost or value of
allowances is expected to escalate significantly. It appears
that the prospects for a cap and trade system such as that
proposed in these bills have dimmed significantly since the 2010
midterm elections; however, some form of GHG legislation remains
possible, and the EPA is moving ahead with its efforts to
regulate GHG emissions from certain sources by rule. Any laws or
regulations that may be adopted to restrict or reduce emissions
of U.S. greenhouse gases could require us to incur
increased operating costs associated with the venting or other
emission of
CO2
and other GHGs in natural gas, and could have an adverse effect
on demand for the natural gas and NGLs we gather and process. In
addition, at least 20 states have already taken legal
measures to reduce emissions of greenhouse gases, primarily
through the planned development of greenhouse gas emission
inventories
and/or
regional greenhouse gas cap and trade programs. Depending on the
particular program, we could be required to purchase and
surrender allowances, either for greenhouse gas emissions
resulting from our operations or from combustion of the natural
gas we gather and process. Although we believe we would not be
impacted to a greater degree than other similarly situated
companies, a stringent greenhouse gas control program could have
an adverse affect on our cost of doing business and could reduce
demand for the natural gas and NGLs we gather and process.
In April 2007, the United States Supreme Court found that the
EPA has the authority to regulate
CO2
emissions from automobiles as air pollutants under
the CAA. Although this decision did not address
CO2
emissions from electric generating plants, the EPA has similar
authority under the CAA to regulate air pollutants
from those and other facilities. In December 2009, the EPA
released an Endangerment and Cause or Contribute Findings
for Greenhouse Gases under the Clean Air Act. This finding
concluded that GHG pollution threatens the public health and
welfare of current and future generations. The EPA has adopted
regulations that would require permits for and reductions in GHG
emissions for certain facilities. For example, in late 2010, the
EPA finalized a rule requiring new and modified facilities that
will emit GHGs in excess of certain thresholds to obtain
construction permits that address GHG emissions. The EPA has
also issued Subpart W of the Final Mandatory Reporting of
Greenhouse Gases Rule, which establishes a national GHG
emissions collection and reporting program. This rule requires
petroleum and natural gas systems that emit 25,000 metric tons
of
CO2
equivalents or more per year to begin collecting GHG emissions
data under a new reporting system beginning on January 1,
2011 with the first annual report due March 31, 2012. We
are implementing procedures to ensure compliance with these new
requirements. Since all of our operations occur in the United
States, these regulations, along with any additional federal or
state restrictions on
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emissions of
CO2
that may be imposed in areas of the United States in which we
conduct business, could also adversely affect our cost of doing
business and demand for the natural gas and NGLs we gather and
process.
Water discharges. The Federal Water Pollution
Control Act, or the Clean Water Act, and analogous
state laws impose restrictions and strict controls regarding the
discharge of pollutants or dredged and fill material into state
waters as well as waters of the U.S. and adjacent wetlands.
The discharge of pollutants into regulated waters is prohibited,
except in accordance with the terms of permits issued by the
EPA, the Army Corps of Engineers or an analogous state agency.
Spill prevention, control and countermeasure requirements of
federal laws require appropriate containment berms and similar
structures to help prevent the contamination of regulated waters
in the event of a hydrocarbon spill, rupture or leak. In
addition, the Clean Water Act and analogous state laws require
individual permits or coverage under general permits for
discharges of storm water runoff from certain types of
facilities. These permits may require us to monitor and sample
the storm water runoff from certain of our facilities. Some
states also maintain groundwater protection programs that
require permits for discharges or operations that may impact
groundwater conditions. We believe that we are in material
compliance with these requirements. However, federal and state
regulatory agencies can impose administrative, civil and
criminal penalties for non-compliance with discharge permits or
other requirements of the Clean Water Act and analogous state
laws and regulations. We believe that compliance with existing
permits and compliance with foreseeable new permit requirements
will not have a material adverse effect on our financial
condition, results of operations or cash flows.
Endangered species. The Endangered Species
Act, or ESA, restricts activities that may affect
endangered or threatened species or their habitats. While some
of our pipelines may be located in areas that are designated as
habitats for endangered or threatened species, we believe that
we are in material compliance with the ESA. However, the
designation of previously unidentified endangered or threatened
species could cause us to incur additional costs or become
subject to operating restrictions or bans in the affected states.
Anti-terrorism measures. The Department of
Homeland Security Appropriation Act of 2007 requires the
Department of Homeland Security, or DHS, to issue
regulations establishing risk-based performance standards for
the security of chemical and industrial facilities, including
oil and gas facilities that are deemed to present high
levels of security risk. The DHS issued an interim final
rule in April 2007 regarding risk-based performance standards to
be attained pursuant to this act and, establish chemicals of
interest and their respective threshold quantities that will
trigger compliance. We have determined the extent to which our
facilities are subject to the rule, made the necessary
notifications and determined that the requirements will not have
a material impact on our financial condition, results of
operations or cash flows.
Employees
Neither CMLP nor our General Partner has any employees.
Employees of Crestwood provide services to our General Partner
pursuant to an Omnibus Agreement.
Available
Information and Corporate Governance Documents
Available Information. We file our annual
report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and other documents electronically with the SEC under the
Securities Exchange Act of 1934, as amended. From
time-to-time,
we may also file registration and related statements pertaining
to equity or debt offerings. We provide access free of charge to
all of these SEC filings, as soon as reasonably practicable
after filing or furnishing, on our Internet site located at
www.crestwoodlp.com. The public may also read and copy
any materials that we file with the SEC at the SECs Public
Reference Room at 100 F Street, N.E., Room 1580,
Washington, DC 20549. The public may obtain information on the
operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330.
The public may also obtain such reports from the SECs
Internet website at www.sec.gov.
Our Corporate Governance Guidelines, Code of Business Conduct
and Ethics and the charters of the audit committee and the
conflicts committee of our General Partners board of
directors are also available on our Internet website. We will
also provide, free of charge, a copy of any of our governance
documents listed above upon written request to our General
Partners corporate secretary at our principal executive
office. Our principal executive offices are located at 717 Texas
Avenue, Suite 3150, Houston, Texas 77002. Our telephone
number is
832-519-2200.
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You should carefully consider the following risk factors
together with all of the other information included in this
annual report, when deciding to invest in us. Limited partner
interests are inherently different from capital stock of a
corporation, although many of the business risks to which we are
subject are similar to those that would be faced by a
corporation engaged in a similar business. You should be aware
that the occurrence of any of the events described in this
annual report could have a material adverse effect on our
business, financial condition, results of operations and cash
flows. In such event, we may be unable to make distributions to
our unitholders and the trading price of our common units could
decline.
Risks
Related to our Business
We are
dependent on a limited number of natural gas producers,
including Quicksilver, for the natural gas we gather, treat,
process and transport. A material reduction would result in a
material decline in our volumes, revenue and cash available for
distribution.
We rely on a limited number of customers for our natural gas
throughput. For the year ended December 31, 2010,
Quicksilver accounted for approximately 90% of our natural gas
gathering, processing and transported volumes. Accordingly, we
are indirectly subject, to a significant degree, to the various
risks to which Quicksilver is subject.
We may be unable to negotiate on favorable terms, if at all, any
extension or replacement of our contract with Quicksilver to
gather and process its production after the terms of the
contract expires in 2020. Furthermore, during the term of the
contract and thereafter, even if we are able to renew this
contract, Quicksilver may reduce its drilling activity in our
areas and decrease its production volumes in the Quicksilver
Counties. The loss of a significant portion of the natural gas
volumes supplied by Quicksilver would result in a material
decline in our revenue and cash available for distribution.
Quicksilver has no contractual obligation to develop its
properties in the areas covered by their dedication to us and it
may determine that it is strategically more attractive to direct
its capital spending to other areas. A shift in
Quicksilvers focus away from the areas covered by their
dedication to us could result in reduced volumes gathered and
processed by us and a material decline in our revenue and cash
available for distribution.
We may
not have sufficient available cash to enable us to make cash
distributions to holders of our common units at the current
distribution rate under our cash distribution
policy.
In order to pay the announced cash distributions of $0.43 per
unit per quarter, or $1.72 per unit per year, we will require
available cash of approximately $14.3 million per quarter,
or $57.1 million per year based on the number of general
partner units and common units outstanding on December 31,
2010. We may not have sufficient available cash from operating
surplus each quarter to enable us to pay the announced
distributions. The amount of cash we can distribute depends
principally upon the amount of cash we generate from our
operations, which may fluctuate from quarter to quarter based
on, among other things:
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the fees we charge and the margins we realize for our services;
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the level of production, and the prices of, natural gas, NGLs,
and condensate;
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the volume of natural gas and NGLs we gather and process;
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the level of competition from other midstream energy companies;
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the level of our operating and maintenance and general and
administrative costs;
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prevailing economic conditions;
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the level of capital expenditures we make;
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our ability to make borrowings under our Credit Facility;
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the cost of acquisitions;
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our debt service requirements;
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fluctuations in our working capital needs;
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our ability to access capital markets;
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compliance with our debt agreements; and
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the amount of cash reserves established by our General Partner.
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The
amount of cash we have available for distribution to holders of
our common units depends primarily on our cash flow and not
solely on profitability. Accordingly we may be prevented from
making distributions, even during periods in which we record net
income.
The amount of cash we have available for distribution depends
primarily upon our cash flow and not solely on profitability,
which may be affected by non-cash items. As a result, we may
make cash distributions during periods when we report net
losses, and conversely, we might fail to make cash distributions
during periods when we report net profits.
The amount of available cash we need to pay the announced
distributions on all of our units and on general partner units
for the next four quarters is approximately $57.1 million.
We may not have sufficient available cash from operating surplus
each quarter to enable us to make cash distributions at the
current distribution rate under our cash distribution policy.
Estimates
of oil and gas reserves depend on many assumptions that may turn
out to be inaccurate. Therefore, future volumes of natural gas
on our systems could be less than we anticipate and could
adversely affect our financial performance and our ability to
make cash distributions.
We typically do not obtain independent evaluations of natural
gas reserves connected to our systems. Accordingly, we do not
have independent estimates of total reserves dedicated to our
systems or the anticipated life of such reserves. If the total
reserves or estimated life of the reserves connected to our
systems is less than we anticipate and we are unable to secure
additional sources of natural gas, it could have a material
adverse effect on our business, results of operations, financial
condition and our ability to make cash distributions to our
unitholders.
Because
of the natural decline in production from existing wells in our
area of operations, our success depends on our ability to obtain
new sources of natural gas which is dependent on factors beyond
our control. Any decrease in supplies of natural gas could
result in a material decline in the volumes we gather, process,
treat and compress.
Our gathering systems are connected to wells whose production
will naturally decline over time, which means that our cash
flows associated with these wells will also decline over time.
To maintain or increase throughput levels on our system, we must
continually obtain new natural gas supplies. Our ability to
obtain additional sources of natural gas depends in part on the
level of successful drilling activity near our pipeline systems
by Quicksilver and our ability to compete for volumes from third
parties.
While we have a dedication from Quicksilver which includes
certain producing and non-producing oil and gas properties, we
have no control over the level of drilling activity in our area
of operations, the amount of reserves associated with the wells
drilled or the rate at which wells are produced or the rate at
which production from a well will decline. In addition, we have
no control over producers drilling or production
decisions, which are affected by, among other things, prevailing
and projected energy prices, demand for hydrocarbons, the level
of reserves, geological considerations, governmental
regulations, availability of drilling rigs and other production
and development services and the availability and cost of
capital. Fluctuations in energy prices can greatly affect
investments to develop natural gas reserves. Drilling activity
generally decreases as natural gas prices decrease. Declines in
natural gas prices could have a negative impact on exploration,
development and production activity and, if sustained, could
lead to a material decrease in such activity. Reductions in
exploration or production activity in our area of operations
could lead to reduced utilization of our systems. Because of
these factors, even if natural gas reserves are known to exist
in areas served by our assets, producers may choose not to
develop those reserves.
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Moreover, Quicksilver is not contractually obligated to develop
the reserves and or properties it has dedicated to us. If
reductions in drilling activity or increased competition result
in our inability to obtain new sources of supply to replace the
natural decline of volumes from existing wells, throughput on
our system would decline, which could reduce our revenue, cash
flow and cash available for distribution.
Our
construction of new assets may not result in revenue increases
and is subject to regulatory, environmental, political, legal
and economic risks, which could adversely affect our cash flows,
results of operations and financial condition.
One of the ways we intend to grow our business is through the
construction of new midstream assets. Additions or modifications
to our asset base involve numerous regulatory, environmental,
political and legal uncertainties beyond our control and may
require the expenditure of significant amounts of capital. If we
undertake these projects, they may not be completed on schedule,
at the budgeted cost, or at all. Moreover, our revenue may not
increase as anticipated for a particular project. For instance,
we may construct facilities to capture anticipated future growth
in production in a region in which such growth does not
materialize. Since we are not engaged in the exploration for and
development of natural gas reserves, we may not have access to
third-party estimates of potential reserves in an area prior to
constructing or acquiring facilities in such area. To the extent
we rely on estimates of future production by parties, other than
Quicksilver, in our decision to expand our systems, such
estimates may prove to be inaccurate due to numerous
uncertainties inherent in estimating quantities of future
production. As a result, new facilities may not be able to
attract enough throughput to achieve our expected investment
return, which could adversely affect our results of operations
and financial condition. In addition, expansion of our asset
base generally requires us to obtain new
rights-of-way.
We may be unable to obtain such
rights-of-way
or it may become more expensive for us to obtain or renew
rights-of-way.
If the cost of
rights-of-way
increases, our cash flows could be adversely affected.
If we
do not make acquisitions on economically acceptable terms, our
future growth will be limited.
In addition to expanding our existing systems, we may pursue
acquisitions. If we are unable to make these acquisitions
because we are: (1) unable to identify attractive
acquisition candidates, to analyze acquisition opportunities
successfully from an operational and financial point of view or
to negotiate acceptable purchase contracts with them;
(2) unable to obtain financing for these acquisitions on
economically acceptable terms; or (3) outbid by
competitors; then our future growth and ability to increase
distributions could be limited. Furthermore, even if we do make
acquisitions, these acquisitions may not result in an increase
in the cash generated by operations.
Any acquisition involves potential risks, including, among other
things:
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mistaken assumptions about volumes, revenue and costs, including
synergies;
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an inability to integrate successfully the assets we acquire;
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the assumption of unknown liabilities;
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limitations on rights to indemnity from the seller;
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mistaken assumptions about the overall costs of equity or debt;
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the diversion of managements and employees attention
from other business matters;
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unforeseen difficulties operating in new product areas, with new
customers, or new geographic areas; and
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customer or key employee losses at the acquired businesses.
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We
depend on our midstream assets to generate our revenue, and if
the utilization of these assets was reduced significantly, there
could be a material adverse effect on our revenue, earnings, and
ability to make distributions to our unitholders.
Operations on our midstream assets could be partially curtailed
or completely shut down, temporarily or permanently, as a result
of:
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operational problems, labor difficulties or environmental
proceedings or other litigation that compel curtailing of all or
a portion of the operations;
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catastrophic events at our facilities or at downstream
facilities owned by others;
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lack of transportation or fractionation capacity;
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an inability to obtain sufficient quantities of natural
gas; or
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prolonged reductions in exploration or production activity by
producers in the areas in which we operate.
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The magnitude of the effect on us of any curtailment of our
operations will depend on the length of the curtailment and the
extent of the operations affected by such curtailment. We have
no control over many of the factors that may lead to a
curtailment of operations.
In the event that we are unable to provide either gathering or
processing services, Quicksilver may use others to gather or
process its production as it so determines. In the event that we
are unable to provide either gathering or processing services
for 60 consecutive days, for reasons other than force majeure,
causing Quicksilvers wells to be shut-in (in the case of
gathering) or resulting in Quicksilvers inability to
by-pass our gathering or processing facilities and deliver its
natural gas production to an alternative pipeline (in the case
of processing), Quicksilver has the right to terminate our
gathering and processing agreement as it relates to the affected
wells. In light of our asset concentration, if such a
termination were to occur, it could cause our revenue, earnings
and cash distributions available to distribute to our
unitholders, to decrease significantly.
We
cannot control the operations of gas processing, liquids
fractionation and transportation facilities of third-parties,
and our revenue and cash available for distribution could be
adversely affected.
We depend upon third-party liquids, fractionation and
transportation systems that we do not own. Since we do not own
or operate these assets, their continuing operation is not
within our control. If any of these third-party pipelines and
other facilities becomes unavailable or capacity constrained, it
could have a material adverse effect on our business, financial
condition and results of operations and cash available for
distribution.
A
change in the jurisdictional characterization of some of our
assets by federal, state or local regulatory agencies or a
change in policy by those agencies may result in increased
regulation of our assets, which may cause our revenue to decline
and operating expenses to increase.
Our operations are generally exempt from jurisdiction and
regulation from FERC, but FERC regulation still affects these
businesses and the markets for products derived from these
businesses. FERCs policies and practices across the range
of its oil and natural gas regulatory activities, including, for
example, its policies on open access transportation, ratemaking,
capacity release and market center promotion, indirectly affect
intrastate markets. In recent years, FERC has pursued
pro-competitive policies in its regulation of interstate oil and
natural gas pipelines. However, we have no assurance that FERC
will continue this approach as it considers matters such as
pipeline rates and rules and policies that may affect rights of
access to oil and natural gas transportation capacity. In
addition, the distinction between FERC-regulated transmission
services and federally unregulated gathering services has
regularly been the subject of litigation, so, the classification
and regulation of some of our pipelines could change based on
future determinations by FERC and the courts. If our gas
gathering operations become subject to FERC jurisdiction, the
result may adversely affect the rates we are able to charge and
the services we currently provide, and may include the potential
for a termination of the gathering and processing agreement with
Quicksilver.
State and municipal regulations also affect our business. Common
purchaser statutes generally require gatherers to purchase
without undue discrimination as to source of supply or producer,
as a result, these statutes
20
restrict our right to decide whose production we gather. Federal
law leaves any economic regulation of natural gas gathering to
the states. Texas, the only state in which we currently operate,
has adopted complaint-based regulation of gathering activities,
which allows oil and natural gas producers and shippers to file
complaints with state regulators in an effort to resolve access
and rate grievances. Other state and municipal regulations may
not directly regulate our business, but may nonetheless affect
the availability of natural gas for purchase, processing and
sale, including state regulation of production rates and maximum
daily production allowable from gas wells. While our gathering
lines currently are subject to limited state regulation, there
is a risk that state laws will be changed, which may give
producers a stronger basis to challenge the rates, terms and
conditions of our gathering lines.
We are
subject to environmental laws, regulations and permits,
including greenhouse gas requirements that may expose us to
significant costs, liabilities and obligations.
We are subject to stringent and complex federal, state and local
environmental laws, regulations and permits, relating to, among
other things, the generation, storage, handling, use, disposal,
movement and remediation of natural gas, NGLs, crude oil and
other hazardous materials; the emission and discharge of such
materials to the ground, air and water; wildlife protection; and
the health and safety of our employees. Failure to comply with
these environmental requirements may result in our being subject
to litigation, fines or other sanctions, including the
revocation of permits and suspension of operations. We may incur
significant costs and other compliance costs related to such
requirements.
We could be liable for any environmental contamination at our or
our predecessors currently or formerly owned or operated
properties or third party waste disposal sites, regardless of
whether we were at fault. In addition to potentially significant
investigation and remediation costs, such matters can give rise
to claims from governmental authorities and other third parties
for fines or penalties, natural resource damages, personal
injury and property damage.
Moreover, stricter laws, regulations or enforcement policies
could significantly increase our operational or compliance costs
and the cost of any remediation that may become necessary. For
instance, since August 2009, the Texas Commission on
Environmental Quality has conducted a series of analyses of air
emissions in the Barnett Shale area in response to reported
concerns about high concentrations of benzene in the air near
drilling sites and natural gas processing facilities, and the
analysis could result in the adoption of new air emission
regulatory or permitting limitations that could require us to
incur increased capital or operating costs. Additionally,
environmental groups have advocated increased regulation and a
moratorium on the issuance of drilling permits for new natural
gas wells in the Barnett Shale area. The adoption of any laws,
regulations or other legally enforceable mandates that result in
more stringent air emission limitations or that restrict or
prohibit the drilling of new natural gas wells for any extended
period of time could increase our operating and compliance costs
as well as reduce the rate of production of natural gas
operators with whom the we have a business relationship, which
could have a material adverse effect on our results of
operations and cash flows.
These laws, regulations and permits, and the enforcement and
interpretation thereof, change frequently and generally have
become more stringent over time. In particular, requirements
pertaining to air emissions, including volatile organic compound
emissions, have been implemented or are under development that
could lead us to incur significant costs or obligations or
curtail our operations. For example, greenhouse gas, or
GHG emission regulation is becoming more stringent.
We are currently required to report annual GHG emissions from
some of our operations, and additional GHG emission related
requirements are in various stages of development. The
U.S. Congress is considering legislation that would
establish a nationwide
cap-and-trade
system for GHGs. In addition, the EPA has proposed regulating
GHG emissions from stationary sources pursuant to the Prevention
of Significant Deterioration and Title V provisions of the
federal Clean Air Act. If enacted, such regulations could
require us to modify existing or obtain new permits, implement
additional pollution control technology, curtail operations or
increase significantly our operating costs. Any regulation of
GHG emissions, including through a
cap-and-trade
system, technology mandate, emissions tax, reporting requirement
or other program, could adversely affect our business,
reputation, operating performance and product demand. In
addition, to the extent climate change results in more severe
weather, our customers operations may be disrupted, which
could reduce product demand.
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In addition, various federal and state initiatives are underway
to regulate, or further investigate the environmental impacts of
hydraulic fracturing, a practice that involves the pressurized
injection of water, chemicals and other substances into rock
formations to stimulate hydrocarbon production. To the extent
these initiatives reduce the volume of natural gas or associated
NGLs that we gather and process, they could adversely affect our
business.
Our costs, liabilities and obligations relating to environmental
matters could have a material adverse effect on our business,
reputation, results of operations and financial condition.
We may
incur significant costs as a result of pipeline integrity
management program testing.
The DOT requires pipeline operators to develop integrity
management programs for pipelines located where a leak or
rupture could harm high consequence areas. The
regulations require operators, including us, to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline
segments that could impact a high consequence area;
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maintain processes for data collection, integration and analysis;
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repair and remediate pipelines as necessary; and
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implement preventive and mitigating actions.
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We currently estimate that we will incur future costs of
approximately $0.8 million through 2015 to complete the
testing required by existing DOT regulations. This estimate does
not include the costs, if any, for repair, remediation,
preventative or mitigating actions that may be determined to be
necessary as a result of the testing program, which could be
substantial.
If we
are unable to obtain needed capital or financing on satisfactory
terms, our ability to make cash distributions may be diminished
or our financial leverage could increase.
Historically, we have used our cash flow from operations,
borrowings under our Credit Facility and issuances of equity to
fund our capital program, working capital needs and
acquisitions. Our capital program may require additional
financing above the level of cash generated by our operations to
fund our growth. If our cash flow from operations decreases as a
result of lower throughput volumes on our gathering and
processing systems or otherwise, our ability to expend the
capital necessary to expand our business or increase our future
cash distributions may be limited. If our cash flow from
operations is insufficient to satisfy our financing needs, we
cannot be certain that additional financing will be available to
us on acceptable terms or at all. Our ability to obtain bank
financing or to access the capital markets for future equity or
debt offerings may be limited by our financial condition or
general economic conditions at the time of any such financing or
offering. Even if we are successful in obtaining the necessary
funds, the terms of such financings could have a material
adverse effect on our business, results of operations, financial
condition and ability to make distributions to our unitholders.
Further, incurring additional debt may significantly increase
our interest expense and financial leverage and issuing
additional limited partner interests may result in significant
unitholder dilution and would increase the aggregate amount of
cash required to maintain the cash distribution rate, which
could materially decrease our ability to pay distributions. If
additional capital resources are unavailable, we may curtail our
activities or be forced to sell some of our assets on an
untimely or unfavorable basis.
We do
not own all of the land on which our pipelines and facilities
are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and
facilities have been constructed, which subjects us to the
possibility of more onerous terms or increased costs to obtain
and maintain valid easements and
rights-of-way.
We obtain standard easement rights to construct and operate our
pipelines on land owned by third parties. Our rights generally
revert back to the landowner after we stop using the easement
for its specified purpose. Therefore, these easements exist for
varying periods of time. Our loss of easement rights could have
a material adverse effect on our ability to operate our
business, thereby resulting in a material reduction in our
revenue, earnings and ability to make cash distributions.
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Our
business involves many hazards and operational risks, some of
which may not be adequately covered by insurance. The occurrence
of a significant accident or other event that is not adequately
insured could curtail our operations and have a material adverse
effect on our business, results of operations, financial
condition and ability to make cash distributions.
Our operations are subject to many risks inherent in the
midstream industry including:
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damage to pipelines and plants, related equipment and
surrounding properties caused by natural disasters and acts of
terrorism;
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inadvertent damage from construction, farm and utility equipment;
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leaks or losses of natural gas or NGLs as a result of the
malfunction of equipment or facilities;
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fires and explosions; and
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other hazards that could also result in personal injury, loss of
life, pollution or suspension of operations.
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These risks could result in curtailment or suspension of our
related operations. A natural disaster or other hazard affecting
the areas in which we operate could have a material adverse
effect on our operations. We maintain insurance against some,
but not all, of such risks and losses in accordance with
customary industry practice. For example, we do not have any
property insurance on any of our underground pipeline systems
that would cover damage to the pipelines. We are not insured
against all environmental incidents, claims or damages that
might occur. Any significant accident or event that is not
adequately insured could adversely affect our business, results
of operations and financial condition. In addition, we may be
unable to economically obtain or maintain the insurance that we
desire. As a result of market conditions, premiums and
deductibles for certain of our insurance policies could escalate
further. In some instances, certain insurance could become
unavailable or available only at reduced coverage levels. Any
type of catastrophic event could have a material adverse effect
on our business, results of operations, financial condition and
ability to make cash distributions.
The
provisions of our Credit Facility and the risks associated with
our debt could adversely affect our business, financial
condition, results of operations, ability to make distributions
to unitholders and value of our units.
Our Credit Facility restricts our ability to, among other things:
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incur additional debt or guarantee other indebtedness;
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make distributions on, redeem or repurchase units;
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make certain investments and acquisitions;
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incur or permit certain liens to exist;
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enter into certain types of transactions with affiliates;
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merge, consolidate or amalgamate with another company; and
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transfer or otherwise dispose of assets.
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Our Credit Facility, among other things, requires the
maintenance of financial covenants that are more fully described
in Note 7 to the consolidated financial statements in
Item 8 of this annual report. Our ability to comply with
the covenants and other provisions of our Credit Facility may be
affected by events beyond our control, and we may be unable to
comply with all aspects of our Credit Facility in the future.
The provisions of our Credit Facility may affect the manner in
which we obtain future financing, pursue attractive business
opportunities and plan for and react to changes in business
conditions. In addition, failure to comply with the provisions
of our Credit Facility could result in an event of default which
could enable the applicable creditors to declare the outstanding
principal and accrued interest to be immediately due and
payable. If we were unable to repay the accelerated amounts, our
lenders could proceed against the collateral granted to them to
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secure such debt. If the payment of our debt is accelerated, we
may have insufficient assets to repay such debt in full, and our
unitholders could experience a partial or total loss of their
investment.
We are
exposed to the credit risks of Quicksilver, and third-party
customers and any material non-payment or non-performance by
these customers could reduce our ability to make distributions
to our unitholders.
We are dependent on Quicksilver for the volumes that we gather
and process, and are consequently subject to the risk of
non-payment or non-performance by Quicksilver.
Quicksilvers credit ratings are below investment grade,
where we expect them to remain for the foreseeable future.
Accordingly, this risk is higher than it would be with a more
creditworthy customer or with a more diversified group of
customers. Unless and until we significantly diversify our
customer base, we expect to remain subject to non-diversified
risk of non-payment or late payment of our fees. Any material
non-payment or non-performance by Quicksilver could reduce our
ability to make distributions to our unitholders. Furthermore,
Quicksilver is highly leveraged and subject to its own operating
and regulatory risks, which could increase the risk that it may
default on its obligations to us.
In October 2010, members of the Darden family sent a letter to
Quicksilvers board of directors in which they expressed an
interest in pursuing strategic alternatives for Quicksilver,
including potentially taking Quicksilvers equity interests
private. Additionally, Quicksilvers board of directors
formed a transaction committee, which retained independent legal
and investment banking firms to assist it in evaluating
potential and any prospective outcomes pursuant to any strategic
alternative. Should the process result in significant changes to
Quicksilvers organizational structure or financial
condition, this could have a material effect on our business and
results of operations.
The
loss of key personnel could adversely affect our ability to
operate.
Our success is dependent upon the efforts of our senior
management, as well as on our ability to attract and retain
senior management. Our senior executive officers have
significant experience in the natural gas industry and have
developed strong relationships with a broad range of industry
participants. The loss of any of these executives could have a
material adverse effect on our relationships with these industry
participants, prevent us from implementing our business
strategy, and our results of operations and our ability to make
distributions to our unitholders.
We do not have employees. We rely solely on officers and
employees of Crestwood to operate and manage our business.
We may
incur additional general and administrative costs as a result of
the Crestwood Transaction.
Historically, we have relied on certain operating, maintenance,
general and administrative and other resources of Quicksilver to
operate our business. Costs allocated to us were based on
identification of Quicksilvers resources which directly
benefit us and our estimated usage of shared resources and
functions. As a result of the closing of the Crestwood
Transaction, and upon completion or termination of the
transition services agreement with Quicksilver, we expect we
will be obligated to bear the full burden of general and
administrative costs for Crestwood and its subsidiaries under
the Omnibus Agreement.
Risks
Inherent in an Investment in us
Crestwood
owns and controls our General Partner, which has sole
responsibility for conducting our business and managing our
operations. Crestwood and our General Partner have conflicts of
interest with, and may favor, Crestwoods interests to the
detriment of our unitholders.
Crestwood owns and controls our General Partner, and appoints
all of the directors of our General Partner. Some of our General
Partners directors, and some of its executive officers,
are directors or officers of Crestwood or its affiliates.
Although our General Partner has a fiduciary duty to manage us
in a manner beneficial to us and our unitholders, the directors
and officers of our General Partner have a fiduciary duty to
manage our General Partner in a manner beneficial to Crestwood.
Therefore, conflicts of interest may arise between Crestwood and
its affiliates, including our General Partner, on the one hand,
and us and our unitholders, on the other hand. In resolving
these
24
conflicts of interest, our General Partner may favor its own
interests and the interests of its affiliates over the interests
of our unitholders.
Crestwood
is not limited in its ability to compete with us and is not
obligated to offer us the opportunity to acquire additional
assets or businesses, which could limit our ability to grow and
could adversely affect our results of operations and cash
available for distribution to our unitholders.
Crestwood is not prohibited from owning assets or engaging in
businesses that compete directly or indirectly with us. In
addition, in the future, Crestwood may acquire, construct or
dispose of additional midstream or other assets and may be
presented with new business opportunities, without any
obligation to offer us the opportunity to purchase or construct
such assets or to engage in such business opportunities.
Moreover, while Crestwood may offer us the opportunity to buy
additional assets from it, it is under no contractual obligation
to do so and we are unable to predict whether or when such
acquisitions might be completed.
Cost
reimbursements due to Crestwood and our General Partner for
services provided to us or on our behalf will be substantial and
will reduce our cash available for distribution to our
unitholders. The amount and timing of such reimbursements will
be determined by our General Partner.
Prior to making distributions on our common units, we will
reimburse our General Partner and its affiliates for all
expenses they incur on our behalf. These expenses will include
all costs incurred by Crestwood and our General Partner in
managing and operating us. Our partnership agreement provides
that our General Partner will determine in good faith the
expenses that are allocable to us. The reimbursements to
Crestwood and our General Partner will reduce the amount of cash
otherwise available for distribution to our unitholders.
If you
are not an eligible holder, you may not receive distributions or
allocations of income or loss on your common units and your
common units will be subject to redemption.
We have adopted certain requirements regarding those investors
who may own our common units. Eligible holders are
U.S. individuals or entities subject to U.S. federal
income taxation on the income generated by us or entities not
subject to U.S. federal income taxation on the income
generated by us, so long as all of the entitys owners are
U.S. individuals or entities subject to such taxation. If
you are not an eligible holder, our General Partner may elect
not to make distributions or allocate income or loss on your
units and you run the risk of having your units redeemed by us
at the lower of your purchase price cost and the then-current
market price. The redemption price will be paid in cash or by
delivery of a promissory note, as determined by our General
Partner.
Our
General Partners liability regarding our obligations is
limited.
Our General Partner included provisions in its and our
contractual arrangements that limit its liability under
contractual arrangements so that the counterparties to such
arrangements have recourse only against our assets, and not
against our General Partner or its assets. Our General Partner
may therefore cause us to incur indebtedness or other
obligations that are nonrecourse to our General Partner. Our
Partnership Agreement provides that any action taken by our
General Partner to limit its liability is not a breach of our
General Partners fiduciary duties, even if we could have
obtained more favorable terms without the limitation on
liability. In addition, we are obligated to reimburse or
indemnify our General Partner to the extent that it incurs
obligations on our behalf. Any such reimbursement or
indemnification payments would reduce the amount of cash
otherwise available for distribution to our unitholders.
Our
Partnership Agreement requires that we distribute all of our
available cash, which could limit our ability to grow and make
acquisitions.
We expect that we will distribute all of our available cash to
our unitholders and will rely primarily upon external financing
sources, including commercial bank borrowings and the issuance
of debt and equity securities, to fund our acquisitions and
expansion capital expenditures. As a result, to the extent we
are unable to finance growth externally, our cash distribution
policy will significantly impair our ability to grow.
In addition, because we distribute all of our available cash,
our growth may not be as fast as that of businesses that
reinvest their available cash to expand ongoing operations. To
the extent we issue additional units in connection with any
acquisitions or expansion capital expenditures, the payment of
distributions on those additional units may
25
increase the risk that we will be unable to maintain or increase
our per-unit
distribution level. There are no limitations in our Partnership
Agreement or in Crestwoods credit facility, on our ability
to issue additional units, including units ranking senior to the
common units. The incurrence of additional commercial borrowings
or other debt to finance our growth strategy would result in
increased interest expense, which, in turn, may impact the
available cash that we have to distribute to our unitholders.
Our
General Partner may elect to cause us to issue Class B and
general partner units to it in connection with a resetting of
the target distribution levels related to its incentive
distribution rights, without the approval of the special
committee of its board of directors or the holders of our common
units. This could result in lower distributions to holders of
our common units.
Our General Partner has the right, at any time when there are no
subordinated units outstanding and it has received incentive
distributions at the highest level to which it is entitled (48%
for each of the prior four consecutive fiscal quarters), to
reset the initial target distribution levels at higher levels
based on our distributions at the time of the exercise of the
reset election. Following a reset election by our General
Partner, the minimum quarterly distribution will be adjusted to
equal the reset minimum quarterly distribution and the target
distribution levels will be reset to correspondingly higher
levels based on percentage increases above the reset minimum
quarterly distribution.
If our General Partner elects to reset the target distribution
levels, it will be entitled to receive a number of Class B
units and general partner units. The Class B units will be
entitled to the same cash distributions per unit as our common
units and will be convertible into an equal number of common
units. The number of Class B units to be issued to our
General Partner will be equal to that number of common units
which would have entitled their holder to an average aggregate
quarterly cash distribution in the prior two quarters equal to
the average of the distributions to our General Partner on the
incentive distribution rights in the prior two quarters. Our
General Partner will be issued the number of general partner
units necessary to maintain our General Partners interest
in us that existed immediately prior to the reset election. We
anticipate that our General Partner would exercise this reset
right in order to facilitate acquisitions or internal growth
projects that would not be sufficiently accretive to cash
distributions per common unit without such conversion. It is
possible, however, that our General Partner could exercise this
reset election at a time when it is experiencing, or expects to
experience, declines in the cash distributions it receives
related to its incentive distribution rights and may, therefore,
desire to be issued Class B units, which are entitled to
distributions on the same priority as our common units, rather
than retain the right to receive incentive distributions based
on the initial target distribution levels. As a result, a reset
election may cause our common unitholders to experience a
reduction in the amount of cash distributions that our common
unitholders would have otherwise received had we not issued new
Class B units and general partner units to our General
Partner in connection with resetting the target distribution
levels.
Holders
of our common units have limited voting rights and are not
entitled to elect our General Partner or its
directors.
Unlike the holders of common stock in a corporation, unitholders
have only limited voting rights on matters affecting our
business and, therefore, limited ability to influence
managements decisions regarding our business. Unitholders
will have no right on an annual or ongoing basis to elect our
General Partner or its board of directors. The board of
directors of our General Partner are chosen by Crestwood.
Furthermore, if the unitholders are dissatisfied with the
performance of our General Partner, they will have little
ability to remove our General Partner. As a result of these
limitations, the price at which the common units will trade
could be diminished because of the absence or reduction of a
takeover premium in the trading price. Our Partnership Agreement
also contains provisions limiting the ability of unitholders to
call meetings or to acquire information about our operations, as
well as other provisions limiting the unitholders ability
to influence the manner or direction of management.
Even
if holders of our common units are dissatisfied, they cannot
initially remove our General Partner without its
consent.
The unitholders initially will be unable to remove our General
Partner without its consent because our General Partner and its
affiliates currently own sufficient units to be able to prevent
its removal. The vote of the holders of at
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least
662/3%
of all outstanding limited partner units voting together as a
single class is required to remove our General Partner. As of
December 31, 2010, Crestwood owns 62.7% of our outstanding
common units.
Our
Partnership Agreement restricts the voting rights of certain
unitholders owning 20% or more of our common
units.
Unitholders voting rights are further restricted by a
provision of our Partnership Agreement providing that any units
held by a person that owns 20% or more of any class of units
then outstanding, other than our General Partner, its
affiliates, their transferees and persons who acquired such
units with the prior approval of the board of directors of our
General Partner, cannot vote on any matter.
Our
General Partner interest or the control of our General Partner
may be transferred to a third party without unitholder
consent.
Our General Partner may transfer its General Partner interest to
a third party in a merger or in a sale of all or substantially
all of its assets without the consent of the unitholders.
Furthermore, our Partnership Agreement does not restrict the
ability of Crestwood to transfer all or a portion of its
ownership interest in our General Partner to a third party. The
new owner of our General Partner would then be in a position to
replace the board of directors and officers of our General
Partner with its own designees and thereby exert significant
control over the decisions made by the board of directors and
officers.
We may
issue additional units without unitholder approval, which would
dilute existing ownership interests.
Our Partnership Agreement does not limit the number of
additional limited partner interests that we may issue at any
time without the approval of our unitholders. The issuance by us
of additional common units or other equity securities of equal
or senior rank will have the following effects:
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our existing unitholders proportionate ownership interest
in us will decrease;
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the amount of cash available for distribution on each unit may
decrease;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit
may be diminished; and
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the market price of the common units may decline.
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Crestwood
may sell units in the public or private markets, and such sales
could have an adverse impact on the trading price of the common
units.
As of December 31, 2010, Crestwood holds an aggregate of
19,544,089 common units. The sale of any or all of these units
in the public or private markets could have an adverse impact on
the price of the common units or on any trading market on which
common units are traded.
Our
General Partner has a limited call right that may require
existing unitholders to sell their units at an undesirable time
or price.
If at any time our General Partner and its affiliates own more
than 80% of the common units, our General Partner will have the
right, which it may assign to any of its affiliates or to us,
but not the obligation, to acquire all, but not less than all,
of the common units held by unaffiliated persons at a price that
is not less than their then-current market price. As a result,
existing unitholders may be required to sell their common units
at an undesirable time or price and may not receive any return
on their investment. Existing unitholders may also incur a tax
liability upon a sale of their units. As of December 31,
2010, Crestwood owns approximately 62.7% of our outstanding
common units.
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Unitholders
liability may not be limited if a court finds that unitholder
action constitutes control of our business.
A general partner of a partnership generally has unlimited
liability for the obligations of the partnership, except for
those contractual obligations of the partnership that are
expressly made without recourse to the general partner. The
limitations on the liability of holders of limited partner
interests for the obligations of a limited partnership have not
been clearly established in some states. A unitholder could be
liable in some circumstances for any and all of our obligations
as if that unitholder were a general partner if a court or
government agency were to determine that:
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we were conducting business in a state but had not complied with
the applicable limited partnership statute; or
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unitholders right to act with other unitholders to remove
or replace our General Partner, to approve some amendments to
our partnership agreement or to take other actions under our
partnership agreement constitute control of our
business.
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Unitholders
may have liability to repay distributions that were wrongfully
distributed to them.
Under certain circumstances, unitholders may have to repay
amounts wrongfully returned or distributed to them. Under
Section 17-607
of the Delaware Revised Uniform Limited Partnership Act, we may
not make a distribution to unitholders if the distribution would
cause our liabilities to exceed the fair value of our assets.
Delaware law provides that for a period of three years from the
date of an impermissible distribution, limited partners who
received the distribution and who knew at the time of the
distribution that it violated Delaware law will be liable to the
limited partnership for the distribution amount. Substituted
limited partners are liable both for the obligations of the
assignor to make contributions to the partnership that were
known to the substituted limited partner at the time it became a
limited partner and for those obligations that were unknown if
the liabilities could have been determined from the partnership
agreement. Neither liabilities to partners on account of their
partnership interest nor liabilities that are non-recourse to
the partnership are counted for purposes of determining whether
a distribution is permitted.
The
market price of our common units could be volatile due to a
number of factors, many of which are beyond our
control.
The market price of our common units could be subject to wide
fluctuations in response to a number of factors, most of which
we cannot control, including, changes in securities
analysts recommendations; publics reaction to our
press releases, announcements and our filings with the SEC;
fluctuations in broader securities market prices and volumes,
particularly among securities of midstream companies and
securities of publicly-traded limited partnerships; changes in
market valuations of similar companies; departures of key
personnel; commencement of or involvement in litigation;
variations in our quarterly results of operations or those of
midstream companies; variations in the amount of our quarterly
cash distributions; future issuances and sales of our common
units; and changes in general conditions in the
U.S. economy, financial markets or the midstream industry.
Risks
Related to the Frontier Acquisition
Our
pending acquisition of Frontier may not be
consummated.
Our pending acquisition of Frontier is expected to close in the
second quarter of 2011 and is subject to customary closing
conditions and regulatory approvals. If these conditions and
regulatory approvals are not satisfied or waived, the
acquisition will not be consummated. If the closing of the
acquisition is substantially delayed or does not occur at all,
or if the terms of the acquisition are required to be modified
substantially due to regulatory concerns, we may not realize the
anticipated benefits of the acquisition fully or at all. Certain
of the conditions remaining to be satisfied include:
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timely approval under the
Hart-Scott-Rodino
Antitrust Improvements Act of 1976 (the HSR Act) for
the transaction contemplated by the Frontier Purchase and Sale
Agreement;
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the continued accuracy of the representations and warranties
contained in the Frontier Purchase and Sale Agreement;
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the performance by each party of its obligations under the
Frontier Purchase and Sale Agreement; and
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the absence of any injunction, decree or other order from any
governmental authority enjoining or prohibiting, or of any law
being enacted which would prohibit, the consummation of the
transactions contemplated in the Frontier Purchase and Sale
Agreement.
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In addition, the Frontier Purchase and Sale Agreement may be
terminated by mutual agreement of the parties or by either
Frontier or us (i) if the acquisition has not closed on or
before May 18, 2011(the Termination Date),
(ii) if approval of the transactions contemplated by the
Frontier Purchase and Sale Agreement under the HSR Act is
required and is not obtained prior to 75 days after
February 18, 2011, (iii) if the other party has
breached its obligations under the Frontier Purchase and Sale
Agreement, which breaches have not been cured in 30 days,
(iv) if any order permanently prohibiting the consummation
of the transactions contemplated thereby has become final and
non-appealable, or (v) by mutual agreement of Frontier and
us in writing. The Bridge Loans commitment expires upon the
earliest to occur of (i) the termination of the Frontier
Purchase and Sale Agreement in accordance with its own terms or
(ii) 90 days after February 18, 2011.
The
closing of the Frontier Acquisition is not subject to a
financing condition and the Bridge Loans do not backstop the
equity portion of the purchase price or our equity
commitments.
The closing of the Frontier Acquisition is not subject to a
financing condition. The Class C Unit Purchase Agreement,
the proceeds of which are to fund a portion of the Frontier
purchase price, is subject to certain closing conditions.
Furthermore, the Bridge Loans commitment does not backstop the
equity portion of the purchase price or our equity commitments
from the Class C Unit Purchasers and the Bridge Loans would
be subject to certain conditions prior to borrowings thereunder.
Although obtaining the equity or debt financing is not a
condition to the completion of the Frontier Acquisition, our
failure to have sufficient funds available to pay the purchase
price is likely to result in the failure of the Frontier
Acquisition to be completed or could require us to sell assets
in order to satisfy our obligations to close.
The
representations, warranties, and indemnifications by Frontier
are limited in the Frontier Purchase and Sale Agreement; as a
result, the assumptions on which our estimates of future results
of the Frontier Assets have been based may prove to be incorrect
in a number of material ways, resulting in us not realizing the
expected benefits of the Frontier Assets.
The representations and warranties by Frontier are limited in
the Frontier Purchase and Sale Agreement. In addition, the
Frontier Purchase and Sale Agreement does not provide any
indemnities other than those described above. As a result, the
assumptions on which our estimates of future results of the
Frontier Assets have been based may prove to be incorrect in a
number of material ways, resulting in us not realizing our
expected benefits of the Frontier Acquisition.
We may not be able to achieve our current expansion plans for
the Frontier Assets on economically viable terms, if at all. In
connection with this expansion effort, we may encounter
difficulties. These risks include the following:
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unexpected operational events;
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adverse weather conditions;
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regulatory hurdles;
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facility or equipment malfunctions or breakdowns;
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a shortage of skilled labor; and
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risks associated with subcontractors services, supplies,
cost escalation and personnel.
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Financing
the Frontier Acquisition will substantially increase our
leverage. We may not be able to obtain debt financing for the
acquisition on expected or acceptable terms.
We intend to finance the Frontier Acquisition and related fees
and expenses with the proceeds of the issuance of equity and
debt, including the private placement of Class C Units,
and, to the extent necessary or desirable, with borrowing under
our revolving credit facility, borrowings under the Bridge
Loans, the issuance of senior unsecured notes
and/or cash
on hand. After completion of the Frontier Acquisition, we expect
our total outstanding indebtedness will increase from
approximately $284 million as of December 31, 2010 to
at least $469 million. The increase in our indebtedness may
reduce our flexibility to respond to changing business and
economic conditions or to fund capital expenditures or working
capital needs.
We intend to raise long term debt in advance of closing of the
Frontier Acquisition. The assumptions underlying our estimate
that the Frontier Acquisition will be accretive to our
distributable cash flow per Common Unit includes assumptions
about the interest rate we will be able to obtain in connection
with such long term debt. We may not be able to obtain debt
financing for the acquisition on expected or acceptable terms.
The
acquisition of the Frontier Assets could expose us to additional
unknown and contingent liabilities.
The acquisition of the Frontier Assets could expose us to
additional unknown and contingent liabilities. We have performed
a certain level of due diligence in connection with the
acquisition of the Frontier Assets and have attempted to verify
the representations made by Frontier, but there may be unknown
and contingent liabilities related to the Frontier Assets of
which we are unaware. Frontier has not agreed to indemnify us
for losses or claims relating to the operation of the business
or otherwise except to the limited extent described above. There
is a risk that we could ultimately be liable for unknown
obligations relating to the Frontier Assets for which
indemnification is not available, which could materially
adversely affect our business, results of operations, financial
condition, and ability to make cash distributions.
Tax Risks
to Common Unitholders
Our
tax treatment depends on our being treated as a partnership for
federal income tax purposes, as well as our not being subject to
a material amount of additional entity-level taxation by
individual states. If the Internal Revenue Service were to treat
us as a corporation or if we become subject to a material amount
of additional entity-level taxation for state tax purposes, then
it would substantially reduce the amount of cash available for
distribution to our unitholders.
The anticipated after-tax economic benefit of an investment in
the common units depends largely on our being treated as a
partnership for federal income tax purposes. As long as we
qualify to be treated as a partnership for federal income tax
purposes, in general we will not be subject to federal income
tax. Although a publicly-traded limited partnership is generally
treated as a corporation for federal income tax purposes, a
publicly-traded partnership such as us can qualify to be treated
as a partnership for federal income tax purposes under current
law so long as for each taxable year at least 90% of its gross
income is derived from specified investments and activities. We
believe that we qualify to be treated as partnership for federal
income tax purposes because we believe that at least 90% of our
gross income for each taxable year has been and is derived from
such specified investments and activities. Although we intend to
meet this gross income requirement, we may not find it possible,
regardless of our efforts, to meet this gross income requirement
or may inadvertently fail to meet this gross income requirement.
If we do not meet this gross income requirement for any taxable
year and the Internal Revenue Service, or IRS, does not
determine that such failure was inadvertent, we would be treated
as a corporation for such taxable year and each taxable year
thereafter. We have not requested, and do not plan to request, a
ruling from the IRS on this or any other tax matter affecting us.
If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income
at the corporate tax rate, which is currently a maximum of
35 percent. Distributions would generally be taxed again as
corporate distributions, and no income, gains, losses,
deductions or credits would flow through. If we were treated as
a corporation at the state level, we would likely also be
subject to entity-level state income tax at varying rates.
Moreover, because of widespread state budget deficits and other
reasons, several states are evaluating ways to subject
partnerships to entity-level taxation through the imposition of
state income, franchise or other forms
30
of taxation. We are for example, subject to an entity-level tax
in Texas. The imposition of any entity-level taxation, including
a federal income tax imposed on us as a corporation or any
entity-level state taxes, will reduce the amount of cash we can
distribute each quarter to the holders of our common units.
Therefore, our treatment as a corporation for federal income tax
purposes or becoming subject to a material amount of additional
state taxes could result in a material reduction in the
anticipated cash flow and after-tax return to the unitholders,
likely causing a substantial reduction in the value of our
common units.
The
tax treatment of publicly traded partnerships or an investment
in our common units could be subject to potential legislative,
judicial or administrative changes and differing
interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly
traded partnerships, including us, or an investment in our
common units may be modified by administrative, legislative or
judicial interpretation at any time. For example, in response to
certain events that occurred in previous years, members of
Congress have considered substantive changes to the existing
U.S. tax laws including the definition of qualifying income
under Section 7704(d) of the Internal Revenue Code and the
treatment of certain types of income earned from profits
interests in partnerships. Although the legislation considered
would not have appeared to affect our tax treatment, we are
unable to predict whether any such change or other proposals
will ultimately be enacted. Moreover, any modification to the
federal income tax laws and interpretations thereof may or may
not be applied retroactively and could make it more difficult or
impossible for us to meet the exception to be treated as a
partnership for U.S. federal income tax purposes that is
not taxable as a corporation, affect or cause us to change our
business activities, affect the tax considerations of an
investment in us, change the character or treatment of portions
of our income, adversely affect an investment in our common
units or otherwise negatively impact the value of an investment
in our common units.
We
prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. The IRS may challenge this treatment, which could
change the allocation of items of income, gain, loss and
deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between
transferors and transferees of our units each month based upon
the ownership of our units on the first day of each month,
instead of on the basis of the date a particular unit is
transferred. The use of this proration method may not be
permitted under existing Treasury Regulations. If the IRS were
to challenge this method or new Treasury Regulations were
issued, we may be required to change the allocation of items of
income, gain, loss and deduction among our unitholders.
An
Internal Revenue Service contest of the federal income tax
positions we have taken or may take may adversely affect the
market for our common units, and the cost of any Internal
Revenue Service contest will reduce our cash available for
distribution to our unitholders.
We have not requested any ruling from the IRS with respect to
our treatment as a partnership for federal income tax purposes
or any other matter affecting us. The IRS may adopt positions
that differ from the positions we have taken or may take. It may
be necessary to resort to administrative or court proceedings to
sustain some or all of the positions we have taken or may take.
A court may not agree with some or all the positions we have
taken or may take. Any contest with the IRS may materially and
adversely impact the market for our common units and the price
at which they trade. In addition, the costs of any contest with
the IRS will result in a reduction in cash available to pay
distributions to our unitholders and our General Partner and
thus will be borne indirectly by our unitholders and our General
Partner.
Unitholders
will be required to pay taxes on their share of our income even
if they do not receive any cash distributions from
us.
Because our unitholders will be treated as partners to whom we
will allocate taxable income which could be different in amount
than cash we distribute, they will be required to pay federal
income taxes and, in some cases, state, local and foreign income
taxes on their allocable share of our taxable income, whether or
not cash is
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distributed from us. Cash distributions may not equal a
unitholders share of our taxable income or even equal the
actual tax liability that results from the unitholders
allocable share of our taxable income.
The
tax gain or loss on the disposition of our common units could be
different than expected.
If our unitholders sell units, they will recognize a gain or
loss equal to the difference between the amount realized and
their tax basis in those common units. Prior distributions to
them in excess of the total net taxable income they were
allocated for a common unit, which decreased their tax basis in
that common unit, will, in effect, become taxable income to them
if the common unit is sold at a price greater than their tax
basis in that common unit, even if the price they receive is
less than their original cost. A substantial portion of the
amount realized, regardless of whether such amount represents
gain, may be taxed as ordinary income to our unitholders due to
potential recapture items, including depreciation recapture. In
addition, if they sell their units, they may incur a tax
liability in excess of the amount of cash they receive from the
sale.
Tax-exempt
entities and foreign persons face unique tax issues from owning
common units that may result in adverse tax consequences to
them.
Investment in common units by tax-exempt entities, such as
employee benefit plans, individual retirement accounts (known as
IRAs), Keogh plans and other retirement plans, regulated
investment companies, real estate investment trusts, mutual
funds and
non-United
States persons raises issues unique to them. For example,
virtually all of our income allocated to organizations that are
exempt from federal income tax, including IRAs and other
retirement plans, will be unrelated business taxable income and
will be taxable to them. Distributions to
non-United
States persons will be reduced by withholding taxes at the
highest applicable effective tax rate, and
non-United
States persons will be required to file United States federal
income tax returns and pay tax on their share of our taxable
income. Tax-exempt entities or foreign persons should consult
their tax advisor regarding their investment in our common units.
We
will treat each purchaser of units as having the same tax
benefits without regard to the actual common units purchased.
The IRS may challenge this treatment, which could result in a
unitholder owing more tax and could otherwise adversely affect
the value of the common units.
Because we cannot match transferors and transferees of common
units, we will adopt depreciation and amortization positions
that may not conform with all aspects of existing Treasury
Regulations. Any position we take that is inconsistent with
applicable Treasury Regulations may have to be disclosed on our
federal income tax return. This disclosure increases the
likelihood that the IRS will challenge our positions and propose
adjustments to some or all of our unitholders. A successful IRS
challenge to those positions could adversely affect the amount
of tax benefits available to our unitholders. It also could
affect the timing of these tax benefits or the amount of gain
from their sale of our common units and could have a negative
impact on the value of our common units or result in audit
adjustments to their tax returns.
We may
adopt certain valuation methodologies that may result in a shift
of income, gain, loss and deduction between the general partner
and the unitholders. The IRS may challenge this treatment, which
could adversely affect the value of the common
units.
When we issue additional units or engage in certain other
transactions, we will determine the fair market value of our
assets and allocate any unrealized gain or loss attributable to
our assets to the capital accounts of our unitholders and our
General Partner. Our methodology may be viewed as understating
the value of our assets. In that case, there may be a shift of
income, gain, loss and deduction between certain unitholders and
the general partner, which may be unfavorable to such
unitholders. Moreover, under our methodologies subsequent
purchasers of common units may have a greater portion of their
Internal Revenue Code Section 743(b) adjustment allocated
to our tangible assets and a lesser portion allocated to our
intangible assets. The IRS may challenge our methods, or our
allocation of the Section 743(b) adjustment attributable to
our tangible and intangible assets, and allocations of income,
gain, loss and deduction between the general partner and certain
of our unitholders.
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A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
gain from our unitholders sale of common units and could
have a negative impact on the value of the common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions.
The
sale or exchange of 50 percent or more of our capital and
profits interests during any
12-month
period will result in the termination of our partnership for
federal income tax purposes.
We will be considered to have terminated our partnership for
federal income tax purposes if there is a sale or exchange of
50 percent or more of the total interests in our capital
and profits within a twelve-month period. Our termination would,
among other things, result in the closing of our taxable year
for all unitholders and could result in a deferral of
depreciation deductions allowable in computing our taxable
income. Our termination currently would not affect our
classification as a partnership for federal income tax purposes,
but instead, we would be treated as a new partnership for
federal tax purposes. If treated as a new partnership for
federal tax purposes, we must make new tax elections and could
be subject to penalties if we are unable to determine that a
termination occurred.
Unitholders
may become subject to state and local taxes and return filing
requirements in states where they do not live as a result of
their investment in our common units.
In addition to federal income taxes, unitholders will likely be
subject to other taxes, including foreign, state and local
taxes, unincorporated business taxes and estate, inheritance, or
intangible taxes that are imposed by the various jurisdictions
in which we do business or own property, even if they do not
live in any of those jurisdictions. Unitholders will likely be
required to file state and local income tax returns and pay
state and local income taxes in some or all of these various
jurisdictions. Further, unitholders may be subject to penalties
for failure to comply with those requirements. As we make
acquisitions or expand our business, we may own assets or
conduct business in additional states that impose an income tax.
It is the unitholders responsibility to file all required
federal, foreign, state and local tax returns.
A
unitholder whose common units are loaned to a short
seller to cover a short sale of common units may be
considered as having disposed of those common units. If so, such
unitholder would no longer be treated for tax purposes as a
partner with respect to those common units during the period of
the loan and may recognize gain or loss from the
disposition.
Because a unitholder whose common units are loaned to a
short seller to cover a short sale of common units
may be considered as having disposed of those common units, such
unitholder may no longer be treated as a partner with respect to
those common units during the period of the loan to the short
seller and the unitholder may recognize gain or loss from such
disposition. Moreover, during the period of the loan to the
short seller, any of our income, gain, loss or deduction with
respect to those common units may not be reportable by the
unitholder and any cash distributions received by the unitholder
as to those common units could be fully taxable as ordinary
income. Unitholders desiring to assure their status as partners
and avoid the risk of gain recognition from a loan to a short
seller are urged to modify any applicable brokerage account
agreements to prohibit their brokers from borrowing their common
units.
|
|
Item 1B.
|
Unresolved
Staff Comments
|
None.
A detailed description of our properties and associated 2010
developments is included in Item 1 of this annual report
and is incorporated herein by reference.
33
|
|
Item 3.
|
Legal
Proceedings
|
We are not a party to any legal proceeding other than legal
proceedings arising in the ordinary course of our business and
disputes normally incident to our business. At December 31,
2010, we are not subject to any material lawsuits or other legal
proceedings.
34
PART II
|
|
Item 5.
|
Market
For Registrants Common Equity, Related Stockholder Matters
and Issuer Purchase of Equity Securities
|
Market
Information
Our common units are currently traded on the NYSE under the
symbol CMLP. The following table sets forth the high
and low sales prices of our common units and the per unit
distributions paid for the periods indicated below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Common
|
|
|
|
|
|
Quarter Ended
|
|
High
|
|
|
Low
|
|
|
Unit
|
|
|
Record Date
|
|
Payment Date
|
|
March 31, 2009
|
|
$
|
14.84
|
|
|
$
|
10.06
|
|
|
$
|
0.37
|
|
|
May 5, 2009
|
|
May 15, 2009
|
June 30, 2009
|
|
$
|
14.78
|
|
|
$
|
11.46
|
|
|
$
|
0.37
|
|
|
Aug. 4, 2009
|
|
Aug. 14, 2009
|
September 30, 2009
|
|
$
|
17.88
|
|
|
$
|
13.52
|
|
|
$
|
0.39
|
|
|
Nov. 3, 2009
|
|
Nov. 13, 2009
|
December 31, 2009
|
|
$
|
22.77
|
|
|
$
|
17.20
|
|
|
$
|
0.39
|
(1)
|
|
Feb. 2, 2010
|
|
Feb. 12, 2010
|
March 31, 2010
|
|
$
|
21.20
|
|
|
$
|
18.58
|
|
|
$
|
0.39
|
|
|
May 4, 2010
|
|
May 14, 2010
|
June 30, 2010
|
|
$
|
22.19
|
|
|
$
|
16.41
|
|
|
$
|
0.42
|
|
|
Aug. 3, 2010
|
|
Aug. 13, 2010
|
September 30, 2010
|
|
$
|
24.68
|
|
|
$
|
18.99
|
|
|
$
|
0.42
|
|
|
Nov. 2, 2010
|
|
Nov. 12, 2010
|
December 31, 2010
|
|
$
|
28.65
|
|
|
$
|
24.46
|
|
|
$
|
0.43
|
(2)
|
|
Feb. 1, 2011
|
|
Feb. 11, 2011
|
|
|
|
(1) |
|
The fourth quarter 2009 distribution is reflected as 2010
activity, since distributions are recorded when paid. |
|
(2) |
|
The fourth quarter 2010 distribution will be reflected as 2011
activity, since distributions are recorded when paid. |
The last reported sale price of our common units on the NYSE on
February 14, 2011, was $29.71. As of that date, we had
eight unitholders of record, which does not include beneficial
owners whose units are held by a clearing agency, such as a
broker or bank.
Cash
Distribution Policy
Our cash distribution policy reflects a basic judgment that our
unitholders are best served by our distributing cash available
after expenses and reserves rather than retaining it. We will
strive to finance our maintenance capital expenditures through
cash generated from operations and to distribute all of our
available cash. Since we are not directly subject to federal
income tax, we have more cash to distribute to unitholders than
would be the case were we subject to such tax. Our Partnership
Agreement requires that we distribute all of our available cash
quarterly, except under certain types of circumstances. Our
ability to make quarterly distributions is subject to certain
restrictions, including restrictions under our debt agreements
and Delaware law.
35
Performance
Graph
The following performance graph compares the cumulative total
unitholder return on our common units with the
Standard & Poors 500 Stock Index (S&P
500) and the Alerian MLP Index for the period from
August 7, 2007 to December 31, 2010, assuming an
initial investment of $100.
Comparison
of Cumulative Total Return
36
|
|
Item 6.
|
Selected
Financial Data
|
The information in this section should be read in conjunction
with Items 7 and 8 of this annual report. In January 2010
we closed the Alliance Acquisition, which was comprised of the
Alliance Midstream Assets originally acquired by Quicksilver in
August 2008. Due to Quicksilvers control of the
Partnership through its ownership of the General Partner at the
time of the Alliance Acquisition, the Alliance Acquisition is
considered a transfer of net assets between entities under
common control. As a result, the Partnership is required to
revise its financial statements to include the financial results
and operations of the Alliance Midstream Assets. As such, the
selected financial data gives retroactive effect to the Alliance
Acquisition as if the Partnership owned the Alliance Midstream
Assets since August 8, 2008, the date which Quicksilver
acquired the Alliance Midstream Assets. The following table
includes selected financial data as of and for each of the five
years in the period ended December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands, except per unit and volume data)
|
|
|
Operating Results Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
113,590
|
|
|
$
|
95,881
|
|
|
$
|
76,084
|
|
|
$
|
35,695
|
|
|
$
|
13,918
|
|
Total operating expenses
|
|
|
65,718
|
|
|
|
52,473
|
|
|
|
38,933
|
|
|
|
22,513
|
|
|
|
11,340
|
|
Operating income
|
|
|
47,872
|
|
|
|
43,408
|
|
|
|
37,151
|
|
|
|
13,182
|
|
|
|
2,578
|
|
Income before income taxes
|
|
|
34,322
|
|
|
|
34,890
|
|
|
|
28,725
|
|
|
|
9,161
|
|
|
|
2,591
|
|
Net income from continuing operations
|
|
|
34,872
|
|
|
|
34,491
|
|
|
|
28,472
|
|
|
|
8,848
|
|
|
|
2,456
|
|
Loss from discontinued operations
|
|
|
|
|
|
|
(1,992
|
)
|
|
|
(2,330
|
)
|
|
|
(592
|
)
|
|
|
(35
|
)
|
Net income
|
|
|
34,872
|
|
|
|
32,499
|
|
|
|
26,142
|
|
|
|
8,256
|
|
|
|
2,421
|
|
Diluted earnings per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
From continuing operations per unit
|
|
$
|
1.03
|
|
|
$
|
1.25
|
|
|
$
|
1.03
|
|
|
$
|
0.22
|
|
|
|
n/a
|
|
Net earnings per unit
|
|
$
|
1.03
|
|
|
$
|
1.18
|
|
|
$
|
0.95
|
|
|
$
|
0.20
|
|
|
|
n/a
|
|
Cash distributions per unit(1)
|
|
$
|
1.66
|
|
|
$
|
1.52
|
|
|
$
|
1.39
|
|
|
$
|
0.47
|
|
|
|
n/a
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
48,003
|
|
|
$
|
68,949
|
|
|
$
|
52,572
|
|
|
$
|
14,949
|
|
|
$
|
6,445
|
|
Investing activities
|
|
|
(149,345
|
)
|
|
|
(54,818
|
)
|
|
|
(148,079
|
)
|
|
|
(73,797
|
)
|
|
|
(78,360
|
)
|
Financing activities
|
|
|
100,598
|
|
|
|
(13,688
|
)
|
|
|
94,685
|
|
|
|
57,176
|
|
|
|
74,712
|
|
Volumes gathered (MMcf)
|
|
|
125,317
|
|
|
|
93,955
|
|
|
|
70,617
|
|
|
|
34,284
|
|
|
|
14,263
|
|
Volumes processed (MMcf)
|
|
|
46,660
|
|
|
|
54,386
|
|
|
|
56,225
|
|
|
|
30,802
|
|
|
|
13,496
|
|
Adjusted gross margin (2)(4)
|
|
$
|
70,231
|
|
|
$
|
64,237
|
|
|
$
|
50,282
|
|
|
$
|
20,884
|
|
|
$
|
5,506
|
|
EBITDA (3)(4)
|
|
|
70,231
|
|
|
|
64,238
|
|
|
|
50,293
|
|
|
|
21,120
|
|
|
|
5,519
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Condition Information:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
531,371
|
|
|
$
|
482,497
|
|
|
$
|
441,863
|
|
|
$
|
254,555
|
|
|
$
|
128,456
|
|
Total assets
|
|
|
570,627
|
|
|
|
487,624
|
|
|
|
502,606
|
|
|
|
278,410
|
|
|
|
134,623
|
|
Long-term debt
|
|
|
283,504
|
|
|
|
125,400
|
|
|
|
174,900
|
|
|
|
5,000
|
|
|
|
|
|
Other long-term obligations(5)
|
|
|
9,877
|
|
|
|
62,162
|
|
|
|
123,928
|
|
|
|
118,306
|
|
|
|
503
|
|
Partners capital
|
|
|
258,753
|
|
|
|
284,837
|
|
|
|
115,208
|
|
|
|
110,200
|
|
|
|
118,652
|
|
|
|
|
(1) |
|
Reported amounts include the fourth quarter distribution on all
common units paid in the first quarter of the subsequent year. |
|
(2) |
|
Defined as total revenues less operations and maintenance
expense and general and administrative expense. Additional
information regarding Adjusted Gross Margin, including a
reconciliation of Adjusted Gross Margin to Net Income as
determined in accordance with GAAP, is included in Results
of Operations in Item 7 of this annual report. |
37
|
|
|
(3) |
|
Defined as net income plus income tax provision, interest
expense, and depreciation and accretion expense. Additional
information regarding EBITDA, including a reconciliation of
EBITDA to Net Income as determined in accordance with GAAP, is
included in Results of Operations in Item 7 of
this annual report. |
|
(4) |
|
For 2006, adjusted gross margin and EBITDA of $5.5 million
less $3.1 million in depreciation and accretion expense
equals reported net income of $2.4 million. |
|
(5) |
|
Other long-term obligations include the subordinated note
payable to Crestwood, and Quicksilver prior to October 1,
2010, which was converted to common units in the fourth quarter
of 2010, repurchase obligations to Quicksilver, which concluded
in the forth quarter of 2009 and asset retirement obligations. |
38
|
|
ITEM 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
The following is a discussion of our historical consolidated
financial condition and results of operations that is intended
to help the reader understand our business, results of
operations and financial condition. It should be read in
conjunction with other sections of this annual report, including
our historical consolidated financial statements and
accompanying notes thereto included in Item 8.
This MD&A includes the following sections:
|
|
|
|
|
Current Year Highlights
|
|
|
|
Overview and Performance Metrics
|
|
|
|
Results of Operations
|
|
|
|
Liquidity and Capital Resources
|
|
|
|
Critical Accounting Estimates
|
Current
Year Highlights
The following key events took place during 2010 which have
impacted or are likely to impact our financial condition and
results of operations:
Alliance
Midstream Assets Acquisition
During January 2010, we completed the purchase of the Alliance
Midstream Assets, located in Tarrant and Denton Counties of
Texas, from Quicksilver for $84.4 million. Subsequent to
the acquisition, we have invested approximately $50 million
in capital to expand the gathering system and increase the
capacity of the facility to 300 MMcfd. Gathered volumes on
the Alliance System in the year ended December 31, 2010
averaged 140 MMcfd. The Alliance System has contributed
$28.0 million in revenue and incurred $10.3 million in
expense for 2010.
Equity
Offering
In January 2010, the underwriters of our equity offering
exercised their option to purchase an additional 549,200 common
units, which resulted in additional proceeds of
$11.1 million. We used $11 million from the sale of
the additional units to pay down our old credit facility.
Crestwood
Transaction
On October 1, 2010, the Crestwood Transaction closed and
Quicksilver sold all of its ownership interests in us to
Crestwood. The Crestwood Transaction includes Crestwoods
purchase of a 100% interest in our General Partner, 5,696,752
common units and 11,513,625 subordinated limited partner units
in CMLP and a note payable by CMLP which had a balance of
approximately $58 million at closing. Quicksilver received
from Crestwood $701 million in cash and has the right to
receive additional cash payments from Crestwood in 2012 and 2013
of up to $72 million in the aggregate. The additional
payments will be determined by an earn-out formula which is
based upon our actual gathering volumes during 2011 and 2012.
The earn-out provision was designed to provide additional
incentive for our largest customer, Quicksilver, to maximize
volumes through our pipeline systems and processing facilities.
The costs associated with the additional earn-out payments will
not be future obligations of CMLP but will be obligations of
Crestwood.
Under the agreements governing the Crestwood Transaction,
Quicksilver and Crestwood have agreed for two years not to
solicit each others employees and Quicksilver has agreed
not to compete with us with respect to gathering, treating and
processing of natural gas and the transportation of natural gas
liquids in Denton, Hood, Somervell, Johnson, Tarrant, Parker,
Bosque and Erath Counties in Texas. Quicksilver is entitled to
appoint a director to our General Partners board of
directors until the later of the second anniversary of the
closing and such time as Quicksilver generates less than 50% of
our consolidated revenue in any fiscal year. Pursuant to this
provision, Thomas Darden, our former CEO, was appointed to serve
on our General Partners board of directors. Our current
independent directors continue to serve as directors after the
closing of the Crestwood Transaction.
39
In connection with the closing of the Crestwood Transaction,
Quicksilver is providing us with transitional services on a
temporary basis on customary terms. More than 100 experienced
midstream employees who had previously been seconded to us from
Quicksilver became employees of Crestwood. We also entered into
an agreement with Quicksilver for the joint development of areas
governed by certain of our existing commercial agreements and
amended certain of our existing commercial agreements, most
significantly to extend the terms of all Quicksilver gathering
agreements to 2020 and to establish a fixed gathering rate of
$0.55 Mcf at the Alliance System.
Recent
Events
On February 18, 2011, we entered into a Purchase and Sale
Agreement (the Frontier Purchase and Sale Agreement)
with Frontier Gas Services, LLC, a Delaware limited liability
company (Frontier), pursuant to which we agreed to
acquire midstream assets (the Frontier Assets) in
the Fayetteville Shale and the Granite Wash plays for a purchase
price of approximately $338 million, with an additional
$15 million to be paid to Frontier if certain operational
objectives are met within six-months of the closing date (the
Frontier Acquisition). The final purchase price is
payable in cash, and we expect to finance the purchase through a
combination of equity and debt as described below. Consummation
of the Frontier Acquisition is subject to customary closing
conditions and regulatory approval. There can be no assurance
that these closing conditions will be satisfied. We expect to
close the Frontier Acquisition in the second quarter of 2011.
On February 18, 2011, we entered into a Class C Unit
Purchase Agreement (the Class C Unit Purchase
Agreement) with the purchasers named therein (the
Class C Unit Purchasers) to sell approximately
6.2 million Class C Units in a private placement. The
negotiated purchase price for the Class C Units is $24.50
per unit, resulting in gross proceeds to us of approximately
$153 million. If the closing of the private placement is
after the record date for our first quarter 2011 distribution in
respect of our Common Units, the price per Class C Unit
will be reduced by such distribution, but the total purchase
price will remain $153 million, and the number of
Class C Units issued will be increased accordingly. We
intend to use the net proceeds from the private placement to
fund a portion of the purchase price for the Frontier
Acquisition. The private placement of the Class C Units
pursuant to the Class C Unit Purchase Agreement is being
made in reliance upon an exemption from the registration
requirements of the Securities Act pursuant to Section 4(2)
and Regulation D thereof. The closing of the private
placement is subject to certain conditions including
(i) the closing of the Frontier Acquisition, (ii) the
receipt of, or binding commitments to fund the Frontier
Acquisition through (A) equity proceeds of not less than
$150 million pursuant to the Class C Unit Purchase
Agreement, and (B) debt financing of not less than
$185 million from the issuance or incurrence of
(x) borrowings under our Credit Facility,
(y) borrowings under a bridge facility,
and/or
(z) senior unsecured notes, senior subordinated notes
and/or other
debt securities, with the weighted average total effective yield
for the aggregate of all debt in this item (ii)(B) to be no more
than 8.75%, (iii) the adoption of an amendment to our
Partnership Agreement to establish the terms of the Class C
Units, (iv) NYSE approval for listing of the Common Units
to be issued upon conversion of the Class C Units, and
(v) our filing of this annual report with the SEC.
In connection to the Class C Unit Purchase Agreement, we
have agreed to enter into a registration rights agreement with
the Class C Unit Purchasers (the Registration Rights
Agreement). Pursuant to the Registration Rights Agreement,
upon request of a Class C Unit holder, we will be required
to file a resale registration statement to register (i) the
Class C Units issued pursuant to the Class C Unit
Purchase Agreement, (ii) the Common Units issuable upon
conversion of the Class C Units issued, (iii) any
Class C Units issued in respect of the Class C Units
as a distribution in kind in lieu of cash distributions and
(iv) any Class C Units issued as liquidated damages
under the Registration Rights Agreement, as soon as practicable
after such request.
In connection with the proposed Frontier Acquisition, we
obtained a commitment from UBS Loan Finance LLC, UBS Securities
LLC, BNP Paribas, BNP Paribas Securities Corp., Royal Bank of
Canada, RBC Capital Markets, RBS Securities Inc. and the Royal
Bank of Scotland plc for senior unsecured bridge loans in an
aggregate amount up to $200 million (the Bridge
Loans). The commitment will expire upon the earliest to
occur of (i) the termination of the Frontier Purchase and
Sale Agreement in accordance with its own terms or
(ii) 90 days after February 18, 2011.
40
The foregoing description of the Frontier Purchase and Sale
Agreement and the Class C Unit Purchase Agreement is only a
summary, does not purport to be complete and is qualified in its
entirety by reference to the Frontier Purchase and Sale
Agreement and Class C Unit Purchase Agreement, which are
attached as Exhibit 2.3 and Exhibit 10.21,
respectively to this annual report on
Form 10-K
and are included herein by reference.
Overview
and Performance Metrics
We are a growth-oriented Delaware limited partnership engaged in
gathering, processing, compression and treating of natural gas
and delivery of NGLs produced from the Barnett Shale geologic
formation of the Fort Worth Basin located in North Texas.
We began operations in 2004 to provide midstream services
primarily to Quicksilver as well as to other natural gas
producers in this area. Additionally, all of our revenues are
derived from operations in the Fort Worth Basin. During
2010, approximately 90% of our total gathering and processing
volumes were comprised of natural gas owned or controlled by
Quicksilver. Approximately 11% of our gathered volumes are
comprised of natural gas purchased by Quicksilver from Eni SpA
and gathered under Quicksilvers Alliance gathering
agreement.
Our results of our operations are significantly influenced by
the volumes of natural gas gathered and processed through our
systems. We gather, process, compress and treat natural gas
pursuant to fee-based contracts. We do not take title to the
natural gas or associated NGLs that we gather and process, and
therefore, we avoid direct commodity price exposure. However, a
prolonged decrease in the commodity price environment could
result in our customers reducing their production volumes which
would cause a resulting decrease in our revenue. All of our
natural gas volumes gathered and processed during 2010 was
subject to fee-based contracts.
Our management uses a variety of financial and operational
measures to analyze our performance. We view these measures as
important factors affecting our profitability and unitholder
value and therefore we review them monthly for consistency and
to identify trends in our operations. These performance measures
are outlined below:
Volume We must continually obtain new
supplies of natural gas to maintain or increase throughput
volumes on our gathering and processing systems. We are
dependent on Quicksilver for approximately 90% of our throughput
volumes. We routinely monitor producer activity in the areas we
serve to identify new supply opportunities. Our ability to
achieve these objectives is impacted by:
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|
|
the level of successful drilling and production activity in
areas where our systems are located;
|
|
|
|
our ability to compete with other midstream companies for
production volumes; and
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|
our pursuit of new acquisition opportunities which might lead to
new supplies of natural gas.
|
Adjusted Gross Margin We use adjusted gross
margin information to evaluate the relationship between our
gathering and processing revenue and the cost of operating our
facilities, including our general and administrative overhead.
Adjusted gross margin is not a measure calculated in accordance
with GAAP as it does not include deductions for expenses such as
interest and income tax which are necessary to maintain our
business. In measuring our operating performance, adjusted gross
margin should not be considered an alternative to, or more
meaningful than, net income or operating cash flow determined in
accordance with GAAP. Our adjusted gross margin may not be
comparable to a similarly titled measure of another entity
because other entities may not calculate adjusted gross margin
in the same manner. A reconciliation of adjusted gross margin to
amounts reported under GAAP is presented in Results of
Operations.
Operating Expenses We consider operating
expenses in evaluating the performance of our operations. These
expenses are comprised primarily of direct labor, insurance,
property taxes, repair and maintenance expense, utilities and
contract services, and are largely independent of the volumes
through our systems, but may fluctuate depending on the scale of
our operations during a specific period. Our ability to manage
operating expenses has a significant impact on our profitability
and ability to pay distributions.
EBITDA We believe that EBITDA is a widely
accepted financial indicator of a companys operational
performance and its ability to incur and service debt, fund
capital expenditures and make distributions. EBITDA is not a
measure calculated in accordance with GAAP, as it does not
include deductions for items such as depreciation, interest and
income taxes, which are necessary to maintain our business.
EBITDA should not be considered an
41
alternative to net income, operating cash flow or any other
measure of financial performance presented in accordance with
GAAP. EBITDA calculations may vary among entities, so our
computation may not be comparable to EBITDA measures of other
entities. In evaluating EBITDA, we believe that investors should
also consider, among other things, the amount by which EBITDA
exceeds interest costs, how EBITDA compares to principal
payments on debt and how EBITDA compares to capital expenditures
for each period. A reconciliation of EBITDA to amounts reported
under GAAP is presented in Results of Operations.
EBITDA is also used as a supplemental performance measure by our
management and by external users of our financial statements
such as investors, commercial banks, research analysts and
others, to assess:
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|
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financial performance of our assets without regard to financing
methods, capital structure or historical cost basis;
|
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|
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our operating performance as compared to those of other
companies in the midstream industry without regard to financing
methods, capital structure or historical cost basis; and
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the viability of acquisitions and capital expenditure projects
and the rates of return on investment opportunities.
|
Results
of Operations
The following table summarizes our combined results of
operations for each of the three years in the period ended
December 31, 2010:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
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|
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2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except volume data)
|
|
|
Total revenues
|
|
$
|
113,590
|
|
|
$
|
95,881
|
|
|
$
|
76,084
|
|
Operations and maintenance expense
|
|
|
28,392
|
|
|
|
24,035
|
|
|
|
19,395
|
|
General and administrative expense
|
|
|
14,967
|
|
|
|
7,609
|
|
|
|
6,407
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted gross margin
|
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|
70,231
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|
|
|
64,237
|
|
|
|
50,282
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|
Other income
|
|
|
|
|
|
|
1
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
EBITDA
|
|
|
70,231
|
|
|
|
64,238
|
|
|
|
50,293
|
|
Depreciation and accretion expense
|
|
|
22,359
|
|
|
|
20,829
|
|
|
|
13,131
|
|
Interest expense
|
|
|
13,550
|
|
|
|
8,519
|
|
|
|
8,437
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|
Income tax provision (benefit)
|
|
|
(550
|
)
|
|
|
399
|
|
|
|
253
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations
|
|
|
34,872
|
|
|
|
34,491
|
|
|
|
28,472
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|
Loss from discontinued operations
|
|
|
|
|
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|
(1,992
|
)
|
|
|
(2,330
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
34,872
|
|
|
$
|
32,499
|
|
|
$
|
26,142
|
|
|
|
|
|
|
|
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|
|
|
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The following table summarizes our volumes for each of the three
years ended December 31, 2010:
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|
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|
|
|
|
|
|
|
|
|
|
|
|
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|
Gathering
|
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|
Processing
|
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|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
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(MMcf)
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|
|
|
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|
Cowtown System
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|
47,275
|
|
|
|
55,337
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|
|
|
57,550
|
|
|
|
46,660
|
|
|
|
54,386
|
|
|
|
56,225
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|
Lake Arlington Dry System
|
|
|
26,854
|
|
|
|
23,132
|
|
|
|
13,067
|
|
|
|
|
|
|
|
|
|
|
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|
|
Alliance Midstream Assets
|
|
|
51,188
|
|
|
|
15,486
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Total
|
|
|
125,317
|
|
|
|
93,955
|
|
|
|
70,617
|
|
|
|
46,660
|
|
|
|
54,386
|
|
|
|
56,225
|
|
|
|
|
|
|
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|
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|
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|
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42
The following table summarizes the changes in our revenues:
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|
|
|
|
|
|
|
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|
|
|
|
|
|
Gathering
|
|
|
Processing
|
|
|
Other
|
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|
Total
|
|
|
|
|
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|
(In thousands)
|
|
|
|
|
|
Revenue for the year ended ended December 31, 2008
|
|
$
|
39,699
|
|
|
$
|
35,485
|
|
|
$
|
900
|
|
|
$
|
76,084
|
|
Volume changes
|
|
|
13,120
|
|
|
|
(1,161
|
)
|
|
|
|
|
|
|
11,959
|
|
Price changes
|
|
|
7,084
|
|
|
|
363
|
|
|
|
391
|
|
|
|
7,838
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue for the year ended ended December 31, 2009
|
|
$
|
59,903
|
|
|
$
|
34,687
|
|
|
$
|
1,291
|
|
|
$
|
95,881
|
|
Volume changes
|
|
|
19,994
|
|
|
|
(4,927
|
)
|
|
|
|
|
|
|
15,067
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|
Price changes
|
|
|
3,497
|
|
|
|
436
|
|
|
|
(1,291
|
)
|
|
|
2,642
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue for the year ended ended December 31, 2010
|
|
$
|
83,394
|
|
|
$
|
30,196
|
|
|
$
|
|
|
|
$
|
113,590
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
2010
Compared with 2009
Total Revenue and Volumes The increase
in revenue of $17.7 million was due to an increase in the
gathered volumes of natural gas on the Alliance System and LADS.
The increase in the Alliance System volumes was the result of
Quicksilvers drilling program in the area, under a joint
development agreement with ENI, which resulted in an increase of
approximately 100 MMcfd in gathered volumes and
$23.4 million in revenue. The increase of 11 MMcfd of
volumes on the LADS was the result of additional well connects
by producers resulting in a $2.4 million increase in
revenue. These increases were offset by approximately
$6.8 million due to the natural decline rate from existing
wells connected to the Cowtown processing facility as local
producers have recently focused new well connections in the
Alliance and LADS areas.
Operations and Maintenance Expense The
increase in operations and maintenance expense was mainly due to
$3.2 million of higher expenses attributable to the
operation of the Alliance System. We expect the Alliance System
operating costs to decrease in 2011 as we complete construction
of our gathering system and reduce the amount of pipeline
currently leased from Quicksilver. Operating expenses also
increased due to $0.9 million in equity compensation
expensed recognized in the fourth quarter of 2010 as a result of
the
change-in-control
with the Crestwood Transaction.
General and Administrative Expense The
increase in general and administrative expense was due to
$2.9 million of equity compensation expense, as a result of
additional phantom unit grants issued in January 2010 and the
vesting of equity-based compensation resulting from the
change-in-control
with the Crestwood Transaction. General and administrative
expense includes $4.7 million and $1.8 million of
equity-based compensation expense for 2010 and 2009,
respectively. General and administration expense also includes
approximately $2.7 million in costs incurred to transition
systems and administrative functions related to the Crestwood
Transaction. Excluding these non-recurring expenses, general and
administrative expenses increased $1.8 million due
primarily to increased compensation and benefits expense and
costs of a new corporate location.
Adjusted Gross Margin and EBITDA
Adjusted gross margin and EBITDA increased primarily as a
result of the increase in revenues described above. As a
percentage of revenue, adjusted gross margin and EBITDA
decreased from 67% in 2009 to 62% in 2010, primarily due to the
increase in revenues and was partially offset by higher
operations and maintenance expense associated with our current
scale of operations and higher general and administrative
expense.
Depreciation and Accretion Expense
Depreciation and accretion expense increased primarily as a
result of continuing expansion of our asset base, which included
the expansion of the Alliance System.
Interest Expense Interest expense increased
primarily due to the increases in the credit facility
borrowings, principally used to fund capital projects, partially
offset by the absence of any liability related to repurchase
obligations. As a result of the termination of our old credit
facility, we recognized $1.6 million in interest expense to
write-off our remaining deferred financing costs. The increase
was offset by the conclusion of our repurchase obligations
during 2009 for which we have no interest expense for such items
in 2010. During December 2009, we used $80.5 million of
proceeds from our secondary offering to pay down our old credit
facility. During January
43
2010, we re-borrowed $95 million to purchase the Alliance
Midstream Assets and repaid $11 million upon the
underwriters exercise of their over-allotment.
The following table summarizes the details of interest expense
for the year ended December 31, 2010 and 2009.
|
|
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|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Interest cost:
|
|
|
|
|
|
|
|
|
Revolving credit facility
|
|
$
|
11,532
|
|
|
$
|
5,076
|
|
Repurchase obligations
|
|
|
|
|
|
|
1,681
|
|
Subordinated note
|
|
|
2,018
|
|
|
|
2,072
|
|
|
|
|
|
|
|
|
|
|
Total cost
|
|
|
13,550
|
|
|
|
8,829
|
|
Less interest capitalized
|
|
|
|
|
|
|
(310
|
)
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
$
|
13,550
|
|
|
$
|
8,519
|
|
|
|
|
|
|
|
|
|
|
2009
Compared with 2008
Total Revenues and Volumes The
increase in revenue is related to the $9.8 million of
additional compression fees on the Cowtown System where
additional compression assets were placed into service during
2009. The increase in total revenue was also due to
$6.7 million in higher revenue due to increased volumes on
the LADS and $4.2 million in higher revenue on the Alliance
System, partially offset by lower processing volumes.
Additionally, this volume increase was principally due to the
well connections made during 2009 as Quicksilver completed and
brought on-line additional wells in the Lake Arlington and
Alliance areas.
Operations and Maintenance Expense The
increase in operations and maintenance expense was mainly due to
$3.4 million of higher cost attributable to the expansion
of the Alliance System as a result of the addition of the
compression facility and expanded gathering system. In addition,
the increase in operations and maintenance expense was due to
the Corvette Plant that was placed in service in March 2009 and
additional costs to operate compression assets that were placed
into service during 2009. However, the increases in our
operations and maintenance expenses have been less significant
than the increases in our throughput volumes and revenues.
General and Administrative Expense The
increase in general and administrative expense was primarily the
result of our expanded operations and the increase in the
allocable portion of Quicksilvers overhead costs,
primarily related to safety and purchasing and transaction costs
incurred during 2009 related to the Alliance Midstream Assets
purchase. General and administrative expense includes
$1.8 million and $1.2 million of equity-based
compensation for 2009 and 2008, respectively.
Adjusted Gross Margin and EBITDA
Adjusted gross margin and EBITDA increased primarily as a
result of the increase in revenues described above. As a
percentage of revenues, adjusted gross margin and EBITDA
increased from 66% in 2008 to approximately 67% in 2009,
primarily due to the increase in revenues, which were partially
offset by operations and maintenance expense associated with our
current scale of operations and higher general and
administrative expense.
Depreciation and Accretion Expense
Depreciation and accretion expense increased primarily as a
result of the property, plant and equipment placed into service
during 2009 in expanding our gathering network and increasing
our processing and compression capabilities.
Interest Expense Interest expense increased
primarily due to greater amounts outstanding under the old
credit facility throughout 2009, partially offset by lower
repurchase obligation balance and lower effective interest rates.
The following table summarizes the details of interest expense
for the years ended December 31, 2009 and 2008. With the
culmination of our repurchase obligations during 2009, we expect
no interest expense for such items
44
in 2010, although the increased borrowing spreads as a result of
our lenders redetermination will likely result in an
increase to our interest expense:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Interest cost:
|
|
|
|
|
|
|
|
|
Revolving credit facility
|
|
$
|
5,076
|
|
|
$
|
3,158
|
|
Repurchase obligations
|
|
|
1,681
|
|
|
|
4,283
|
|
Subordinated note
|
|
|
2,072
|
|
|
|
2,802
|
|
|
|
|
|
|
|
|
|
|
Total cost
|
|
|
8,829
|
|
|
|
10,243
|
|
Less interest capitalized
|
|
|
(310
|
)
|
|
|
(1,806
|
)
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
$
|
8,519
|
|
|
$
|
8,437
|
|
|
|
|
|
|
|
|
|
|
Liquidity
and Capital Resources
Our sources of liquidity include:
|
|
|
|
|
cash generated from operations;
|
|
|
|
borrowings under our Credit Facility; and
|
|
|
|
future capital market transactions.
|
We believe that the cash generated from these sources will be
sufficient to meet our expected $0.43 per unit quarterly cash
distributions during 2011 and satisfy our short-term working
capital and maintenance capital expenditure requirements.
Since the inception of operations in 2004, our cash flows have
been significantly influenced by Quicksilvers production
in the Fort Worth Basin. As Quicksilver and others have
developed the Fort Worth Basin, we have expanded our
gathering and processing facilities to serve the additional
volumes produced by such development.
Known
Trends and Uncertainties
Our financial condition and results of operations, including our
liquidity and profitability, can be significantly affected by
the following:
|
|
|
|
|
natural gas prices;
|
|
|
|
dependency on Quicksilver and the Fort Worth Basin; and
|
|
|
|
regulatory requirements.
|
The volumes of natural gas that we gather and process are
dependent upon the natural gas volumes produced by our
customers, which may be affected by prevailing natural gas
prices, their derivative programs, and the availability and cost
of capital. We cannot predict future changes to natural gas
prices or how any such pricing changes will influence
producers behaviors. If reduced drilling and development
programs in the Fort Worth Basin were to be sustained over
a prolonged period of time, we could experience a reduction in
volumes through our system and therefore reductions of revenue
and cash flows.
At this time, all of our revenue is derived from our operations
in the Fort Worth Basin. In addition, approximately 90% of
our total gathering and processing revenue is associated with
natural gas volumes owned or controlled by Quicksilver. The risk
of revenue fluctuations in the near-term is somewhat mitigated
by the use of fixed fee contracts for providing gathering and
processing and treating services to our customers, but we are
still susceptible to volume fluctuations. To reduce the
concentration risk associated with our dependency on one
producer and one geographic area, we are regularly reviewing
opportunities for both organic growth projects and acquisitions
in other producing basins and with other producers.
45
We are subject to environmental laws, regulations and permits,
including green house gas requirements that may expose us to
significant costs or obligations. In general, these laws,
regulations, and permits have become more stringent over time
and are subject to further changes and could materially affect
our financial condition and results of operations in the future.
Significant
Economic Factors That Impact our Business
Changes in natural gas supply such as new discoveries of natural
gas reserves, declining production in older fields and the
introduction of new sources of natural gas supply, such as
non-conventional and emerging natural gas shale plays, affect
the demand from producers for our services. As these supply
dynamics change, we anticipate that we will actively pursue
projects that will allow us to provide midstream services to
producers associated with the growth of new sources of supply.
Changes in demographics, the amount of natural gas fired power
generation, liquefied natural gas imports and shifts in
industrial and residential usage affect the overall demand for
natural gas.
We believe that the key factors that impact our business are
natural gas prices, our customers drilling and completion
activities, and government regulation on natural gas pipelines.
These key factors play an important role in how we evaluate our
operations and implement our long-term strategies.
Cash
Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Net cash provided by operating activities
|
|
$
|
48,003
|
|
|
$
|
68,949
|
|
|
$
|
52,572
|
|
Net cash used in investing activities
|
|
|
(149,345
|
)
|
|
|
(54,818
|
)
|
|
|
(148,079
|
)
|
Net cash provided by (used in) financing activities
|
|
|
100,598
|
|
|
|
(13,688
|
)
|
|
|
94,685
|
|
2010
Cash Flows Compared to 2009
Cash Flows Provided by Operating Activities
The decrease in cash flows from operating activities
resulted from an increase in the accounts receivable balance
primarily related to the timing of collections from Quicksilver.
Cash Flows Used in Investing Activities The
increase in cash flows used in investing activities resulted
from the distribution to Quicksilver of $80.3 million
related to the purchase of the Alliance Midstream Assets.
Additionally, for the 2010 period, we spent $69.0 million
for gathering assets and facilities, of which approximately
$50 million relates to the expansion of the gathering
system at Alliance.
Cash Flows Provided by Financing Activities
Changes in cash flows provided by financing activities
during the 2010 period resulted primarily from the net
borrowings under our credit facilities of $158.1 million
compared with the 2009 period pay down under our old credit
facility of $49.5 million. This change is largely
reflective of our funding of the purchase of the Alliance
Midstream Assets for $84.4 million. We also borrowed
$13.6 million to pay financing costs related to our new
Credit Facility. In addition, we distributed $12.8 million
more to our unitholders during the 2010 period due to increases
in our quarterly distributions from December 31, 2009 to
December 31, 2010. In January 2010, the underwriters of our
equity offering exercised their option to purchase an additional
549,200 common units, which generated proceeds of
$11.1 million compared to $80.8 million in 2009.
2009
Cash Flows Compared to 2008
Cash Flows Provided by Operating Activities
The increase in cash flows provided by operating activities
resulted primarily from increased revenues and higher
profitability associated with the natural gas gathered and
processed through our systems, due to factors discussed above in
our results of operations.
Cash Flows Used in Investing Activities The
decrease in cash flows used in investing activities resulted
from the lower capital expenditures used to expand our gathering
system and processing capabilities, particularly due to an
$80 million decrease in spending on plant capital, most
significantly related to spending for the Corvette Plant
construction. In 2009, we spent $26.9 million on gathering
assets, and $27.9 million on processing facilities, which
46
included $26.6 million related to the Corvette Plant. The
cash flows used in investing activities during 2009 include the
payment of $25.8 million that was incurred and accrued at
December 31, 2008.
Cash Flows Used in Financing Activities
Changes in cash flows used in financing activities during
2009 consisted primarily of the 2009 net pay down under our
old credit facility of $49.5 million compared with
2008 net borrowings of $169.9 million. In addition, we
distributed $5.0 million more to our unitholders during
2009. Our secondary offering during December 2009, generated
proceeds of $80.8 million for which there was no comparable
2008 event. Cash flows in 2009 also reflect $36.4 million
of lower payments pursuant to repurchase obligations compared to
2008, when we purchased LADS.
Capital
Expenditures
The midstream energy business is capital intensive, requiring
significant investment for the acquisition or development of new
facilities. We categorize our capital expenditures as either:
|
|
|
|
|
expansion capital expenditures, which are made to construct
additional assets, expand and upgrade existing systems, or
acquire additional assets; or
|
|
|
|
maintenance capital expenditures, which are made to replace
partially or fully depreciated assets, to maintain the existing
operating capacity of our assets and extend their useful lives.
|
Since our inception in 2004, we have made substantial capital
expenditures. We anticipate that we will continue to make
capital expenditures to develop our gathering and processing
network as Quicksilver continues to expand its development
efforts in the Fort Worth Basin. Consequently, our ability
to develop and maintain sources of funds to meet our capital
requirements is critical to our ability to meet our growth
objectives and to maintain our distribution levels.
We have budgeted approximately $37 million in capital
expenditures for 2011, of which $4 million is classified as
maintenance capital expenditures. The capital budget includes
approximately $33 million for the construction of pipelines
and gathering systems, $3 million for compression assets
and $1 million for processing plants. We expect to fund our
capital expenditures through borrowing under our Credit Facility
and from cash generated from operations.
Repurchase
Obligation to Quicksilver
During 2009, our independent directors voted to acquire certain
of the Cowtown Pipeline assets subject to the repurchase
obligation that had an original cost of approximately
$5.6 million. We paid $5.6 million for these assets in
September 2009. Furthermore, our independent directors elected
not to acquire certain Cowtown Pipeline assets that had been
previously included in the repurchase obligation. In doing so,
we derecognized assets with a carrying value of
$56.8 million and also derecognized liabilities associated
with the repurchase of $68.6 million. The difference of
$11.8 million between the assets carrying values and
their repurchase obligation was reflected as an increase in
partners capital effective upon the decision not to
purchase. We also entered into an agreement with Quicksilver to
permit us to gather third party gas for a fee across the Cowtown
Pipeline laterals retained by Quicksilver. The decision not to
purchase certain Cowtown Pipeline assets did not have a material
effect on our gathering and processing revenues as the natural
gas stream from these laterals continues to flow into our
Cowtown Pipeline gathering and processing facilities.
We had been obligated to repurchase from Quicksilver a gas
gathering system in Hill County, Texas, at its fair market value
within two years after its completion and commencement of
commercial service. As a result of this contractual purchase
obligation, we have historically included the HCDS in our
financial statements since our initial public offering. In
November 2009, we and Quicksilver mutually agreed to waive both
parties rights and obligations to transfer ownership of
the HCDS to us. The revenues and expenses directly attributable
to the HCDS for the periods prior to November 2009 have been
retroactively reported as discontinued operations.
For a complete description of our repurchase obligations to
Quicksilver, see Note 2 to our consolidated financial
statements included in Item 8 of this annual report.
47
Other
Matters
We regularly review opportunities for both organic growth
projects and acquisitions that will enhance our financial
performance. Since we strive to distribute most of our available
cash to our unitholders, we will depend on a combination of
borrowings under our Credit Facility, operating cash flows and
debt or equity offerings to finance any future growth capital
expenditures or acquisitions.
Credit
Facility and Subordinated Note
For a complete description of Long Term Debt, see Note 7 to
our consolidated financial statements included in Item 8 of
this annual report.
Total
Contractual Obligations
The following table summarizes our total contractual cash
obligations as of December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
Contractual Obligations
|
|
Total
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
Long-term debt(1)
|
|
$
|
283.5
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
283.5
|
|
|
$
|
|
|
Scheduled interest obligations(2)
|
|
|
42.3
|
|
|
|
8.9
|
|
|
|
8.9
|
|
|
|
8.9
|
|
|
|
8.9
|
|
|
|
6.7
|
|
|
|
|
|
Contractual Obligations(3)
|
|
|
4.0
|
|
|
|
1.6
|
|
|
|
0.8
|
|
|
|
0.7
|
|
|
|
0.5
|
|
|
|
0.4
|
|
|
|
|
|
Asset retirement obligations(4)
|
|
|
9.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations
|
|
$
|
339.7
|
|
|
$
|
10.5
|
|
|
$
|
9.7
|
|
|
$
|
9.6
|
|
|
$
|
9.4
|
|
|
$
|
290.6
|
|
|
$
|
9.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
As of December 31, 2010, we had $283.5 million
outstanding under our Credit Facility. |
|
(2) |
|
Based on our debt outstanding and interest rates in effect at
December 31, 2010, we would anticipate interest payments to
be approximately $8.9 million annually on our Credit
Facility. For each additional $10.0 million in borrowings,
annual interest payments will increase by approximately
$0.3 million. If the committed amount under our Credit
Facility were to be fully utilized by year-end 2011 at interest
rates in effect at December 31, 2010, we estimate that
annual interest expenses would increase by approximately
$3.7 million. If interest rates on our December 31,
2010 variable debt balance of $283.5 million increase or
decrease by one percentage point, our annual income will
decrease or increase by $2.8 million. |
|
(3) |
|
We lease office buildings and other property under operating
leases. |
|
(4) |
|
For more information regarding our asset retirement obligations,
see Note 8 to our consolidated financial statements,
included in Item 8 of this annual report, none of which is
expected to be due before 2015. |
Critical
Accounting Estimates
Management discusses with our Audit Committee the development,
selection and disclosure of our critical accounting policies and
estimates and the application of these policies and estimates.
Our consolidated financial statements are prepared in accordance
with GAAP in the United States. We believe our accounting
policies are appropriately selected and applied.
Use of
Estimates
GAAP requires management to make estimates and judgments that
affect the amounts reported in the financial statements and
notes. These estimates and judgments are based on information
available at the time that we make such estimates and judgments.
These estimates and judgments principally affected the reported
amounts of depreciation expense, asset retirement obligations
and stock-based compensation.
48
Depreciation
Expense and Cost Capitalization Policies
Policy
Description
Our assets consist primarily of natural gas gathering pipelines,
processing plants and compression facilities. We capitalize all
construction-related direct labor and material costs plus the
interest cost associated with financing the construction of new
facilities. These aggregate costs less the estimated salvage
value are then depreciated using the straight-line method over
the estimated useful life of the constructed asset. The costs of
renewals and betterments that extend the useful life or
substantially improve the efficiency of property, plant and
equipment are also capitalized. The costs of repairs,
replacements and normal maintenance projects are expensed as
incurred.
Judgments
and Assumptions
The computation of depreciation expense requires judgment
regarding the estimated useful lives and salvage value of
assets. As circumstances warrant, depreciation estimates are
reviewed to determine if any changes are needed. Such changes
could involve an increase or decrease in estimated useful lives
or salvage values which could impact current and future
depreciation expense. When making expenditures, we also must
determine whether they improve efficiency or extend the useful
life of the underlying assets, to determine whether to
capitalize such amounts paid.
Asset
Retirement Obligations
Policy
Description
In certain instances, we have obligations to remove equipment
and restore land at the end of our
right-of-way
period or the assets useful life. We estimate the amount
and timing of asset retirement expenditures and record the
discounted fair value of asset retirement obligations as a
liability in the period in which it is legally or contractually
incurred. Upon initial recognition of the asset retirement
liability, an asset retirement cost is capitalized by increasing
the carrying amount of the related long-lived asset by the same
amount as the liability. Changes in the liability for the asset
retirement obligation are recognized for both the passage of
time and revisions to either the timing or the amount of the
estimated cash flows. In periods subsequent to initial
measurement, the asset retirement cost is allocated to expense
on a straight-line basis over the assets useful life.
Judgments
and Assumptions
Inherent in the fair value calculation of asset retirement
obligations are numerous assumptions and judgments including the
estimated remaining lives of the wells connected to our systems,
the estimated cost to remove equipment or restore land in the
future, inflation factors, credit adjusted discount rates and
changes in the legal or regulatory requirements. To the extent
future revisions to these assumptions impact the fair value of
our existing asset retirement obligation, a corresponding
adjustment is made to our liability.
Equity-Based
Compensation
Policy
Description
Prior to 2007, we issued no equity-based compensation awards.
During 2008, 2009 and 2010, we issued phantom units to certain
non-management directors and executive officers of our General
Partner and employees of Quicksilver and Crestwood who provide
services to us. An estimate of fair value is determined for all
share-based payment awards on the grant date. Compensation
expense for all share-based payment awards is recognized over
the vesting period for each award.
Judgments
and Assumptions
GAAP requires management to make assumptions and to apply
judgment to determine the fair value of our awards. These
assumptions and judgments include forfeiture rates and estimated
distributions during the vesting period. Changes in these
assumptions can materially affect the fair value estimate.
49
We do not believe there is a reasonable likelihood that there
will be a material change in the future estimates or assumptions
that we use to determine stock-based compensation expense.
However, if actual results are not consistent with our estimates
or assumptions, we may be exposed to changes in stock-based
compensation expense that could be material. If actual results
are not consistent with the assumptions used, the stock-based
compensation expense reported in our financial statements may
not be representative of the actual economic cost of the
stock-based compensation.
Off-Balance
Sheet Arrangements
We have no off-balance sheet arrangements within the meaning of
Item 303(a)(4) of SEC
Regulation S-K.
Recently
Issued Accounting Pronouncements
The information regarding recent accounting pronouncements is
included in Note 2 to our consolidated financial
statements, included in Item 8 of this annual report.
Item
7A. Quantitative
and Qualitative Disclosures About Market Risk
We have established policies and procedures for managing risk
within our organization, including internal controls. The level
of risk assumed by us is based on our objectives and capacity to
manage risk.
Credit
Risk
Our primary credit risk relates to our dependency on Quicksilver
for the majority of our natural gas volumes, which causes us to
be subject to the risk of nonpayment or late payment by
Quicksilver for gathering and processing fees.
Quicksilvers credit ratings are below investment grade,
where they may remain for the foreseeable future. Accordingly,
this risk could be higher than it might be with a more
creditworthy customer or with a more diversified group of
customers. Unless and until we significantly diversify our
customer base, we expect to continue to be subject to
non-diversified risk of nonpayment or late payment of our fees.
Additionally, we perform credit analyses of our customers on a
regular basis pursuant to our corporate credit policy. We have
not had any significant losses due to counter-party failures to
perform.
Interest
Rate Risk
Although our base interest rates remain low, our leverage ratios
directly influence the spreads charged by lenders. The credit
markets could also drive the spreads charged by lenders upward.
As base rates or spreads increase, our financing costs will
increase accordingly. Although this could limit our ability to
raise funds in the capital markets, we expect that our
competitors would face similar challenges with respect to
funding acquisitions and capital projects. We are exposed to
variable interest rate risk as a result of borrowings under our
Credit Facility. The table of contractual obligations contained
in Item 7 of this annual report contains more information
regarding interest rate sensitivity.
50
|
|
Item 8.
|
Financial
Statements and Supplementary Data
|
CRESTWOOD
MIDSTREAM PARTNERS LP
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
51
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
Crestwood Midstream Partners LP
We have audited the accompanying consolidated balance sheets of
Crestwood Midstream Partners LP (formerly Quicksilver Gas
Services LP) and subsidiaries (the Company) as of
December 31, 2010 and 2009, and the related consolidated
statements of income, cash flows, and changes in partners
capital for each of the three years in the period ended
December 31, 2010. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on the financial
statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of
Crestwood Midstream Partners LP and subsidiaries at
December 31, 2010 and 2009, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2010, in conformity with
accounting principles generally accepted in the United States of
America.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
Companys internal control over financial reporting as of
December 31, 2010, based on the criteria established in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated February 25, 2011,
expressed an unqualified opinion on the Companys internal
control over financial reporting.
/s/ Deloitte &
Touche LLP
Fort Worth, Texas
February 25, 2011
52
CRESTWOOD
MIDSTREAM PARTNERS LP
CONSOLIDATED
STATEMENTS OF INCOME
In
thousands, except for per unit data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering revenue related party
|
|
$
|
77,645
|
|
|
$
|
57,593
|
|
|
$
|
34,468
|
|
Gathering revenue
|
|
|
5,749
|
|
|
|
2,310
|
|
|
|
5,231
|
|
Processing revenue related party
|
|
|
27,590
|
|
|
|
32,605
|
|
|
|
30,127
|
|
Processing revenue
|
|
|
2,606
|
|
|
|
2,082
|
|
|
|
5,358
|
|
Other revenue related party
|
|
|
|
|
|
|
1,291
|
|
|
|
900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
113,590
|
|
|
|
95,881
|
|
|
|
76,084
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenance
|
|
|
28,392
|
|
|
|
24,035
|
|
|
|
19,395
|
|
General and administrative
|
|
|
14,967
|
|
|
|
7,609
|
|
|
|
6,407
|
|
Depreciation and accretion
|
|
|
22,359
|
|
|
|
20,829
|
|
|
|
13,131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
65,718
|
|
|
|
52,473
|
|
|
|
38,933
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
47,872
|
|
|
|
43,408
|
|
|
|
37,151
|
|
Other income
|
|
|
|
|
|
|
1
|
|
|
|
11
|
|
Interest expense
|
|
|
13,550
|
|
|
|
8,519
|
|
|
|
8,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income taxes
|
|
|
34,322
|
|
|
|
34,890
|
|
|
|
28,725
|
|
Income tax provision (benefit)
|
|
|
(550
|
)
|
|
|
399
|
|
|
|
253
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations
|
|
|
34,872
|
|
|
|
34,491
|
|
|
|
28,472
|
|
Loss from discontinued operations
|
|
|
|
|
|
|
(1,992
|
)
|
|
|
(2,330
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
34,872
|
|
|
$
|
32,499
|
|
|
$
|
26,142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner interest in net income
|
|
$
|
2,526
|
|
|
$
|
1,172
|
|
|
$
|
647
|
|
Common and subordinated unitholders interest in net income
|
|
$
|
32,346
|
|
|
$
|
31,327
|
|
|
$
|
25,495
|
|
Basic earnings (loss) per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
From continuing operations per common and subordinated unit
|
|
$
|
1.11
|
|
|
$
|
1.38
|
|
|
$
|
1.17
|
|
From discontinued operations per common and subordinated unit
|
|
$
|
|
|
|
$
|
(0.08
|
)
|
|
$
|
(0.10
|
)
|
Net earnings per common and subordinated unit
|
|
$
|
1.11
|
|
|
$
|
1.30
|
|
|
$
|
1.07
|
|
Diluted earnings (loss) per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
From continuing operations per common and subordinated unit
|
|
$
|
1.03
|
|
|
$
|
1.25
|
|
|
$
|
1.03
|
|
From discontinued operations per common and subordinated unit
|
|
$
|
|
|
|
$
|
(0.07
|
)
|
|
$
|
(0.08
|
)
|
Net earnings per common and subordinated unit
|
|
$
|
1.03
|
|
|
$
|
1.18
|
|
|
$
|
0.95
|
|
Weighted average number of common and subordinated units
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
29,070
|
|
|
|
24,057
|
|
|
|
23,783
|
|
Diluted
|
|
|
31,316
|
|
|
|
28,189
|
|
|
|
29,583
|
|
Distributions per unit (attributable to the period ended)
|
|
$
|
1.66
|
|
|
$
|
1.52
|
|
|
$
|
1.39
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
53
CRESTWOOD
MIDSTREAM PARTNERS LP
CONSOLIDATED
BALANCE SHEETS
In
thousands, except for unit data
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
ASSETS
|
Current assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
2
|
|
|
$
|
746
|
|
Accounts receivable
|
|
|
1,679
|
|
|
|
1,342
|
|
Accounts receivable related party
|
|
|
23,003
|
|
|
|
|
|
Prepaid expenses and other
|
|
|
1,052
|
|
|
|
180
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
25,736
|
|
|
|
2,268
|
|
Property, plant and equipment, net
|
|
|
531,371
|
|
|
|
482,497
|
|
Other assets
|
|
|
13,520
|
|
|
|
2,859
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
570,627
|
|
|
$
|
487,624
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current liabilities
|
|
|
|
|
|
|
|
|
Current maturities of debt
|
|
$
|
|
|
|
$
|
2,475
|
|
Accounts payable related party
|
|
|
4,267
|
|
|
|
1,727
|
|
Accrued additions to property, plant and equipment
|
|
|
11,309
|
|
|
|
8,015
|
|
Accounts payable and other
|
|
|
2,917
|
|
|
|
2,240
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
18,493
|
|
|
|
14,457
|
|
Long-term debt
|
|
|
283,504
|
|
|
|
125,400
|
|
Subordinated note payable
|
|
|
|
|
|
|
53,243
|
|
Asset retirement obligations
|
|
|
9,877
|
|
|
|
8,919
|
|
Deferred income taxes
|
|
|
|
|
|
|
768
|
|
Commitments and contingent liabilities (Note 9)
|
|
|
|
|
|
|
|
|
Partners capital
|
|
|
|
|
|
|
|
|
Common unitholders (31,187,696 and 16,313,451 units issued
and outstanding at December 31, 2010 and December 31,
2009, respectively)
|
|
|
258,069
|
|
|
|
281,239
|
|
Subordinated unitholders (0 and 11,513,625 units issued and
outstanding at December 31, 2010 and December 31,
2009, respectively)
|
|
|
|
|
|
|
3,040
|
|
General partner
|
|
|
684
|
|
|
|
558
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
258,753
|
|
|
|
284,837
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
570,627
|
|
|
$
|
487,624
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
54
CRESTWOOD
MIDSTREAM PARTNERS LP
CONSOLIDATED
STATEMENTS OF CASH FLOWS
In
thousands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
34,872
|
|
|
$
|
32,499
|
|
|
$
|
26,142
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
21,848
|
|
|
|
23,046
|
|
|
|
14,545
|
|
Accretion of asset retirement obligations
|
|
|
511
|
|
|
|
394
|
|
|
|
184
|
|
Deferred income taxes
|
|
|
(768
|
)
|
|
|
399
|
|
|
|
196
|
|
Equity-based compensation
|
|
|
5,522
|
|
|
|
1,705
|
|
|
|
1,017
|
|
Non-cash interest expense
|
|
|
4,961
|
|
|
|
6,191
|
|
|
|
9,787
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(270
|
)
|
|
|
740
|
|
|
|
(1,200
|
)
|
Prepaid expenses and other assets
|
|
|
(903
|
)
|
|
|
387
|
|
|
|
(612
|
)
|
Accounts receivable related party
|
|
|
(23,003
|
)
|
|
|
3,621
|
|
|
|
4,002
|
|
Accounts payable related party
|
|
|
4,630
|
|
|
|
|
|
|
|
|
|
Accounts payable and other
|
|
|
603
|
|
|
|
(33
|
)
|
|
|
(1,489
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
48,003
|
|
|
|
68,949
|
|
|
|
52,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(69,069
|
)
|
|
|
(54,818
|
)
|
|
|
(148,079
|
)
|
Distributions to Quicksilver for Alliance Midstream Assets
|
|
|
(80,276
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(149,345
|
)
|
|
|
(54,818
|
)
|
|
|
(148,079
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from revolving credit facility borrowings
|
|
|
426,704
|
|
|
|
56,000
|
|
|
|
169,900
|
|
Debt issuance costs paid
|
|
|
(13,568
|
)
|
|
|
(1,446
|
)
|
|
|
(486
|
)
|
Repayment of repurchase obligation to Quicksilver
|
|
|
|
|
|
|
(5,645
|
)
|
|
|
(42,085
|
)
|
Repayments of credit facility
|
|
|
(268,600
|
)
|
|
|
(105,500
|
)
|
|
|
|
|
Repayment of subordinated note payable to Quicksilver
|
|
|
|
|
|
|
|
|
|
|
(825
|
)
|
Proceeds from issuance of equity units
|
|
|
11,088
|
|
|
|
80,760
|
|
|
|
|
|
Equity issuance cost paid
|
|
|
(34
|
)
|
|
|
(31
|
)
|
|
|
|
|
Contributions by Quicksilver
|
|
|
|
|
|
|
(816
|
)
|
|
|
111
|
|
Distributions to unitholders
|
|
|
(49,699
|
)
|
|
|
(36,947
|
)
|
|
|
(31,930
|
)
|
Taxes paid for equity-based compensation vesting
|
|
|
(5,293
|
)
|
|
|
(63
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
100,598
|
|
|
|
(13,688
|
)
|
|
|
94,685
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash increase (decrease)
|
|
|
(744
|
)
|
|
|
443
|
|
|
|
(822
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
746
|
|
|
|
303
|
|
|
|
1,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
2
|
|
|
$
|
746
|
|
|
$
|
303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
8,590
|
|
|
$
|
4,682
|
|
|
$
|
2,341
|
|
Cash paid for income taxes
|
|
$
|
|
|
|
$
|
|
|
|
$
|
332
|
|
Non-cash transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital related to capital expenditures
|
|
$
|
11,309
|
|
|
$
|
10,105
|
|
|
$
|
31,920
|
|
Costs in connection with the equity offering
|
|
|
|
|
|
|
(416
|
)
|
|
|
|
|
Contribution of property, plant and equipment from Quicksilver
|
|
|
|
|
|
|
72,342
|
|
|
|
9,668
|
|
Disposition (acquisition) of property, plant and equipment under
repurchase obligation, net
|
|
|
|
|
|
|
111,070
|
|
|
|
(77,108
|
)
|
Equity contribution related to assets not purchased pursuant to
repurchase obligations
|
|
$
|
|
|
|
$
|
20,663
|
|
|
$
|
|
|
Repayment of subordinated note
|
|
$
|
57,736
|
|
|
|
|
|
|
$
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
55
CRESTWOOD
MIDSTREAM PARTNERS LP
CONSOLIDATED
STATEMENTS OF CHANGES IN PARTNERS CAPITAL
In
thousands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners Capital
|
|
|
|
Limited Partners
|
|
|
|
|
|
|
|
|
|
Common
|
|
|
Subordinated
|
|
|
General Partner
|
|
|
Total
|
|
|
Balance at December 31, 2007
|
|
$
|
109,830
|
|
|
$
|
356
|
|
|
$
|
14
|
|
|
$
|
110,200
|
|
Equity-based compensation expense recognized
|
|
|
1,017
|
|
|
|
|
|
|
|
|
|
|
|
1,017
|
|
Distributions paid to partners
|
|
|
(16,135
|
)
|
|
|
(15,140
|
)
|
|
|
(655
|
)
|
|
|
(31,930
|
)
|
Contribution by Quicksilver
|
|
|
9,779
|
|
|
|
|
|
|
|
|
|
|
|
9,779
|
|
Net income
|
|
|
13,050
|
|
|
|
12,456
|
|
|
|
636
|
|
|
|
26,142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
117,541
|
|
|
|
(2,328
|
)
|
|
|
(5
|
)
|
|
|
115,208
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity-based compensation expense recognized
|
|
|
1,705
|
|
|
|
|
|
|
|
|
|
|
|
1,705
|
|
Distributions paid to partners
|
|
|
(18,471
|
)
|
|
|
(17,270
|
)
|
|
|
(1,206
|
)
|
|
|
(36,947
|
)
|
Net income
|
|
|
18,384
|
|
|
|
12,926
|
|
|
|
1,189
|
|
|
|
32,499
|
|
Contribution by Quicksilver
|
|
|
81,830
|
|
|
|
9,712
|
|
|
|
580
|
|
|
|
92,122
|
|
Public offering of units, net of offering costs
|
|
|
80,313
|
|
|
|
|
|
|
|
|
|
|
|
80,313
|
|
Other
|
|
|
(63
|
)
|
|
|
|
|
|
|
|
|
|
|
(63
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
281,239
|
|
|
|
3,040
|
|
|
|
558
|
|
|
|
284,837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity-based compensation expense recognized
|
|
|
5,522
|
|
|
|
|
|
|
|
|
|
|
|
5,522
|
|
Distributions paid to partners
|
|
|
(28,648
|
)
|
|
|
(18,651
|
)
|
|
|
(2,400
|
)
|
|
|
(49,699
|
)
|
Net income
|
|
|
22,614
|
|
|
|
9,732
|
|
|
|
2,526
|
|
|
|
34,872
|
|
Distribution to Quicksilver
|
|
|
(80,276
|
)
|
|
|
|
|
|
|
|
|
|
|
(80,276
|
)
|
Public offering of units, net of offering costs
|
|
|
11,054
|
|
|
|
|
|
|
|
|
|
|
|
11,054
|
|
Conversion of subordinated note payable
|
|
|
57,736
|
|
|
|
|
|
|
|
|
|
|
|
57,736
|
|
Conversion of subordinated units
|
|
|
(5,879
|
)
|
|
|
5,879
|
|
|
|
|
|
|
|
|
|
Taxes paid for equity-based compensation vesting
|
|
|
(5,293
|
)
|
|
|
|
|
|
|
|
|
|
|
(5,293
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
$
|
258,069
|
|
|
$
|
|
|
|
$
|
684
|
|
|
$
|
258,753
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
56
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
|
|
1.
|
ORGANIZATION
AND DESCRIPTION OF BUSINESS
|
Organization Crestwood Midstream Partners LP
(CMLP) is a Delaware limited partnership formed for
the purpose of completing a public offering of common units and
concurrently acquiring and operating midstream assets. As of
September 30, 2010 our General Partner was owned by
Quicksilver.
On October 1, 2010, the Crestwood Transaction closed and
Quicksilver sold all of its ownership interests in CMLP to
Crestwood. The Crestwood Transaction includes Crestwoods
purchase of a 100% interest in our General Partner, 5,696,752
common units and 11,513,625 subordinated limited partner units
in CMLP and a note payable by CMLP which had a carrying value of
approximately $58 million at closing. Quicksilver received
from Crestwood $701 million in cash and has the right to
receive additional cash payments from Crestwood in 2012 and 2013
of up to $72 million in the aggregate. The additional
payments will be determined by an earn-out formula which is
based upon our actual gathering volumes during 2011 and 2012.
On October 4, 2010, our name changed from Quicksilver Gas
Services LP to Crestwood Midstream Partners LP and our ticker
symbol on the New York Stock Exchange for our publicly traded
common units changed from KGS to CMLP.
The Crestwood Transaction did not have any direct impact to our
historical financial statements as previously reported. However,
during October 2010, the following significant matters occurred:
|
|
|
|
|
recognition of approximately $3.6 million of costs
associated with the vesting of equity-based compensation of our
phantom units upon the closing of the Crestwood Transaction in
accordance with the
change-in-control
provisions of our 2007 Equity Plan;
|
|
|
|
acceleration of amounts due under our old $320 million
credit facility, which was replaced with a new $400 million
Credit Facility;
|
|
|
|
termination of our omnibus agreement with Quicksilver, which was
replaced with a new Omnibus Agreement;
|
|
|
|
termination of our Services and Secondment Agreement with
Quicksilver which we replaced, on a temporary basis, with a
Transition Services Agreement with Quicksilver;
|
|
|
|
extension of the tenor of all of our gathering and processing
agreements with Quicksilver to 2020; and
|
|
|
|
change to a fixed gathering rate of $0.55 per Mcf for the
Alliance System for Quicksilver to replace the variable rate
which had a range of $0.40 to $0.55 per Mcf.
|
On December 10, 2009, we entered into an underwriting
agreement to offer 4,000,000 common units at a price to the
public of $21.10 per common unit. The total net proceeds that we
received from the equity offering during December 2009, before
expenses, were approximately $81 million. In January 2010,
the underwriters exercised their option to purchase an
additional 549,200 common units, which resulted in additional
proceeds of $11.1 million. During December 2009, we used
the proceeds from our equity offering to temporarily pay down
our old credit facility before finalizing our purchase of the
Alliance Midstream Assets for $84.4 million during 2010. In
January 2010, we used $11 million from the sale of
additional units to the underwriters to pay down our old credit
facility.
As of December 31, 2010, our ownership is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ownership Percentage
|
|
|
|
Crestwood
|
|
|
Public
|
|
|
Total
|
|
|
General partner interest
|
|
|
1.5
|
%
|
|
|
|
|
|
|
1.5
|
%
|
Limited partner interest:
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unitholders
|
|
|
61.7
|
%
|
|
|
36.8
|
%
|
|
|
98.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interests
|
|
|
63.2
|
%
|
|
|
36.8
|
%
|
|
|
100.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
57
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Neither CMLP nor our General Partner has any employees.
Employees of Crestwood provide services to our General Partner
pursuant to an Omnibus Agreement.
Description of Business We are engaged in the
gathering, processing, compression and treating of natural gas
and the delivery of NGLs produced from the Barnett Shale
formation in the Fort Worth Basin located in North Texas.
We provide these midstream services under contracts, whereby we
receive fees for performing gathering, processing, compression
and treating services. We do not take title to the natural gas
or associated NGLs thereby avoiding direct commodity price
exposure.
We conduct our operations through our Cowtown System, Lake
Arlington Dry System and Alliance Midstream Assets and formerly
Hill County Dry System as described below:
Cowtown
System
The Cowtown System, located principally in Hood and Somervell
Counties in the southern portion of the Fort Worth Basin,
which includes:
|
|
|
|
|
the Cowtown Pipeline, consisting of a gathering system and
related gas compression facilities. This system gathers natural
gas produced by our customers and delivers it to the Cowtown and
Corvette Plants for processing;
|
|
|
|
the Cowtown Plant, consisting of two natural gas processing
units with a total capacity of 200 MMcfd that extract NGLs
from the natural gas stream and deliver customers residue
gas and extracted NGLs to unaffiliated pipelines for sale
downstream; and
|
|
|
|
the Corvette Plant, placed in service during 2009, consisting of
a 125 MMcfd natural gas processing unit that extracts NGLs
from the natural gas stream and delivers customers residue
gas and extracted NGLs to unaffiliated pipelines for sale
downstream.
|
Lake
Arlington Dry System
The LADS, located in eastern Tarrant County, consists of a gas
gathering system and related gas compression facility with
capacity of 230 MMcfd. This system gathers natural gas
produced by our customers and delivers it to unaffiliated
pipelines for sale downstream.
Hill
County Dry System
As more fully described in Note 2, our financial
information through November 2009 also included the operations
of a gathering system in Hill County, Texas. The HCDS gathers
natural gas and delivers it to unaffiliated pipelines for
further transport and sale downstream. As of November 2009, the
revenue and expenses directly attributable to the HCDS for the
periods prior to November 2009 have been retrospectively
reported as discontinued operations based upon the execution of
the Repurchase Obligation Waiver. The HCDS had previously been
subject to a repurchase obligation since its 2007 sale to
Quicksilver.
All repurchase obligations to Quicksilver were concluded by
December 31, 2009. Notes 2 and 4 to our financial
statements contain more information regarding the Repurchase
Obligation Waiver.
Alliance
Midstream Assets
During 2010, we completed the purchase of the Alliance Midstream
Assets from Quicksilver for a purchase price of
$84.4 million, which, with subsequent additions, we refer
to as the Alliance System. The Alliance System consists of a
gathering system and related compression facility with a
capacity of 300 MMcfd, an amine treating facility with
capacity of 360 MMcfd and a dehydration treating facility
with capacity of 300 MMcfd. This system gathers natural gas
produced by our customers and delivers it to unaffiliated
pipelines for sale downstream. The
58
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
majority of the Alliance Midstream Assets operations commenced
service in September 2009, although less significant operations
had been conducted prior to that time. Because the purchase of
the Alliance Midstream Assets was conducted among entities then
under common control, GAAP requires the inclusion of the
Alliance Systems revenue and expenses in our income
statements for all periods presented, including periods prior to
our purchase of the system. The following summarizes the impact
of this inclusion:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2009
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Presented
|
|
|
Alliance System
|
|
|
Combined
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Revenue
|
|
$
|
91,706
|
|
|
$
|
4,175
|
|
|
$
|
95,881
|
|
Operating expenses
|
|
|
(47,610
|
)
|
|
|
(4,863
|
)
|
|
|
(52,473
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
44,096
|
|
|
$
|
(688
|
)
|
|
$
|
43,408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per limited partner unit:
|
|
$
|
1.33
|
|
|
$
|
(0.03
|
)
|
|
$
|
1.30
|
|
Diluted earnings (loss) per limited partner unit:
|
|
$
|
1.21
|
|
|
$
|
(0.03
|
)
|
|
$
|
1.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2008
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Presented
|
|
|
Alliance System
|
|
|
Combined
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Revenue
|
|
$
|
76,084
|
|
|
$
|
|
|
|
$
|
76,084
|
|
Operating expenses
|
|
|
(38,659
|
)
|
|
|
(274
|
)
|
|
|
(38,933
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
37,425
|
|
|
$
|
(274
|
)
|
|
$
|
37,151
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) per limited partner unit:
|
|
$
|
1.08
|
|
|
$
|
(0.01
|
)
|
|
$
|
1.07
|
|
Diluted earnings (loss) per limited partner unit:
|
|
$
|
0.96
|
|
|
$
|
(0.01
|
)
|
|
$
|
0.95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009
|
|
|
|
As Previously
|
|
|
|
|
|
|
|
|
|
Presented
|
|
|
Alliance System
|
|
|
Combined
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
396,952
|
|
|
$
|
85,545
|
|
|
$
|
482,497
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
396,952
|
|
|
$
|
85,545
|
|
|
$
|
482,497
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued additions to property, plant and equipment
|
|
$
|
4,011
|
|
|
$
|
4,004
|
|
|
$
|
8,015
|
|
Asset retirement obligations
|
|
|
7,654
|
|
|
|
1,265
|
|
|
|
8,919
|
|
Partners capital
|
|
|
204,561
|
|
|
|
80,276
|
|
|
|
284,837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
216,226
|
|
|
$
|
85,545
|
|
|
$
|
301,771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
Basis of Presentation The accompanying
consolidated financial statements and related notes present the
financial position, results of operations, cash flows and
changes in partners capital of our natural gas gathering
and processing assets. The financial statements include
historical cost-basis accounts of the assets of our Predecessor
which were contributed to us by Quicksilver and two private
investors in connection with the IPO.
59
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Our consolidated financial statements include the accounts of
CMLP and its majority-owned subsidiaries. We eliminate all
inter-company balances and transactions in preparing
consolidated financial statements.
Discontinued Operations In November 2009,
Quicksilver and our General Partner mutually agreed to waive
both parties rights and obligations to transfer ownership
of the HCDS from Quicksilver to us, which we refer to as the
Repurchase Obligation Waiver. The Repurchase Obligation Waiver
caused derecognition of the assets and liabilities directly
attributable to the HCDS, most significantly the property, plant
and equipment and repurchase obligation, beginning in November
2009. In addition, the Repurchase Obligation Waiver caused the
elimination of the HCDS revenues and expenses from our
consolidated results of operations beginning in November 2009.
The revenues and expenses directly attributable to the HCDS for
the periods prior to November 2009 have been retrospectively
reported as discontinued operations.
Use of Estimates The preparation of the
financial statements in accordance with GAAP requires management
to make estimates and judgments that affect the reported amount
of assets, liabilities, revenues and expenses and disclosure of
contingent assets and liabilities that exist at the date of the
financial statements. Estimates and judgments are based on
information available at the time such estimates and judgments
are made. Although management believes the estimates are
appropriate, actual results can differ from those estimates.
Cash and Cash Equivalents We consider all
highly liquid investments with a remaining maturity of three
months or less at the time of purchase to be cash or cash
equivalents. These cash equivalents consist principally of
temporary investments of cash in short-term money market
instruments.
Accounts receivable Accounts receivable are
due from Quicksilver and other independent natural gas
producers. Each of our customers is reviewed as to credit
worthiness prior to the extension of credit and on a regular
basis thereafter. Although we do not require collateral,
appropriate credit ratings are required. Receivables are
generally due within
30-60 days.
At December 31, 2010 and 2009, we have recorded no
allowance for uncollectible accounts receivable. During 2010, we
experienced no significant non-payment for services.
Property, Plant and Equipment Property, plant
and equipment is stated at cost less accumulated depreciation.
Depreciation is computed using the straight-line method over the
estimated useful lives of the assets. The cost of maintenance
and repairs, which are not significant improvements, are
expensed when incurred. Expenditures to extend the useful lives
of the assets or enhance their productivity or efficiency from
their original design are capitalized over the expected
remaining period of use.
Impairment of Long-Lived Assets We review
long-lived assets for impairment whenever events or
circumstances indicate that the carrying amount of an asset may
not be recoverable. If we determine that an assets
estimated future cash flows will not be sufficient to recover
its carrying amount, we would record an impairment charge to
reduce the carrying amount for the asset to its estimated fair
value. At December 31, 2010, our analysis of estimated
future cash flows indicated that there was no impairment on our
long-lived assets.
Other Assets Other assets consist of costs
associated with debt issuance and pipeline license agreements,
net of amortization. Debt issuance costs are amortized over the
term of the associated debt. Pipeline license agreements provide
us the right to construct, operate and maintain certain
pipelines with local municipalities. The pipeline license
agreements are amortized over the initial term of the agreement.
Asset Retirement Obligations We record the
discounted fair value of the liability for asset retirement
obligations in the period in which it is legally or
contractually incurred. Upon initial recognition of the asset
retirement liability, an asset retirement cost is capitalized by
increasing the carrying amount of the long-lived asset by the
same amount as the liability. In periods subsequent to the
initial measurement, the asset retirement cost is allocated to
expense using a straight line method over the assets
useful life. Changes in the liability for the asset retirement
obligation are recognized for (a) the passage of time and
(b) revisions to either the timing or the amount of the
estimated cash flows.
60
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Environmental Liabilities Liabilities for
environmental loss contingencies, including environmental
remediation costs, are charged to expense when it is probable
that a liability has been incurred and the amount of the
assessment or remediation can be reasonably estimated.
Revenue Recognition Our primary service
offerings are the gathering and processing of natural gas. We
have contracts under which we receive revenue based on the
volume of natural gas gathered and processed. We recognize
revenue when all of the following criteria are met:
|
|
|
|
|
persuasive evidence of an exchange arrangement exists;
|
|
|
|
services have been rendered;
|
|
|
|
the price for its services is fixed or determinable; and
|
|
|
|
collectability is reasonably assured.
|
Income Taxes We are subject to a margin tax
that requires tax payments at a maximum statutory effective rate
of 0.7% of the gross revenue apportioned to Texas. The margin
tax qualifies as an income tax under GAAP, which requires us to
recognize currently the impact of this tax on the temporary
differences between the financial statement assets and
liabilities and their tax basis.
Earnings per Limited Partner Unit Our net
income is allocated to the general partner and the limited
partners, in accordance with their respective ownership
percentages, after giving effect to incentive distributions paid
to the general partner. Basic earnings per unit are computed by
dividing net income attributable to limited partner unitholders
by the weighted-average number of limited partner units
outstanding during each period. Diluted earnings per unit are
computed using the treasury stock method, which considers the
impact to net income and common units from the potential
issuance of units and conversion of debt into limited partner
units.
Segment Information We operate solely in the
midstream segment in Texas where we provide natural gas
gathering, treating and processing services.
Fair Value of Financial Instruments The fair
value of accounts receivable, accounts payable and long-term
debt approximate their carrying amounts since they are short
term in nature.
Equity-Based Compensation At time of issuance
of phantom units, our General Partners board of directors
determines whether they will be settled in cash or settled in
our units. For awards payable in cash, we amortize the expense
associated with the award over the vesting period. The liability
for fair value is reassessed at every balance sheet date, such
that the vested portion of the liability is adjusted to reflect
revised fair value through compensation expense. Phantom unit
awards payable in units are valued at the closing market price
of our common units on the date of grant. The unearned
compensation is amortized to compensation expense over the
vesting period of the phantom unit award.
Recently
Issued Accounting Standards
Accounting standard-setting organizations frequently issue new
or revised accounting rules. We regularly review all new
pronouncements to determine their impact, if any, on our
financial statements. There are currently no recent
pronouncements that have been issued which we believe will
materially affect our financial statements.
61
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
3.
|
NET
INCOME PER COMMON AND SUBORDINATED UNIT
|
The following is a reconciliation of the weighted-average common
and subordinated units used in the basic and diluted earnings
per unit calculations for 2010, 2009 and 2008. The impact of the
convertible debt is dilutive for 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Common and subordinated unitholders interest in net income
from continuing operations
|
|
$
|
32,346
|
|
|
$
|
33,286
|
|
|
$
|
27,780
|
|
Common and subordinated unitholders interest in net loss
from discontinued operations
|
|
|
|
|
|
|
(1,959
|
)
|
|
|
(2,285
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common and subordinated unitholders interest in net income
|
|
$
|
32,346
|
|
|
$
|
31,327
|
|
|
$
|
25,495
|
|
Impact of interest on subordinated note
|
|
|
|
|
|
|
2,038
|
|
|
|
2,748
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income available assuming conversion of convertible debt
|
|
$
|
32,346
|
|
|
$
|
33,365
|
|
|
$
|
28,243
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common and subordinated units basic
|
|
|
29,070
|
|
|
|
24,057
|
|
|
|
23,783
|
|
Effect of restricted phantom units
|
|
|
2,246
|
|
|
|
486
|
|
|
|
141
|
|
Effect of subordinated note(1)
|
|
|
|
|
|
|
3,646
|
|
|
|
5,659
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average common and subordinated units
diluted
|
|
|
31,316
|
|
|
|
28,189
|
|
|
|
29,583
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
From continuing operations per common and subordinated unit
|
|
$
|
1.11
|
|
|
$
|
1.38
|
|
|
$
|
1.17
|
|
From discontinued operations per common and subordinated unit
|
|
$
|
|
|
|
$
|
(0.08
|
)
|
|
$
|
(0.10
|
)
|
Net earnings per common and subordinated unit
|
|
$
|
1.11
|
|
|
$
|
1.30
|
|
|
$
|
1.07
|
|
Diluted earnings per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
From continuing operations per common and subordinated unit
|
|
$
|
1.03
|
|
|
$
|
1.25
|
|
|
$
|
1.03
|
|
From discontinued operations per common and subordinated unit
|
|
$
|
|
|
|
$
|
(0.07
|
)
|
|
$
|
(0.08
|
)
|
Net earnings per common and subordinated unit
|
|
$
|
1.03
|
|
|
$
|
1.18
|
|
|
$
|
0.95
|
|
Assumed conversion price(1)
|
|
$
|
|
|
|
$
|
15.28
|
|
|
$
|
9.48
|
|
|
|
|
(1) |
|
Assumes that convertible debt is converted using the lesser of
average closing price per unit or final closing price on
December 31. |
See Note 7 for more information regarding the conversion of
the subordinated note to Quicksilver.
|
|
4.
|
DISCONTINUED
OPERATIONS
|
In November 2009, Quicksilver and our General Partner mutually
agreed to waive both parties rights and obligations to
transfer ownership of the HCDS from Quicksilver to us, which we
refer to as the Repurchase Obligation Waiver. The Repurchase
Obligation Waiver caused derecognition of the assets and
liabilities directly attributable to the HCDS, most
significantly the property, plant and equipment and repurchase
obligation, beginning in November 2009. In addition, the
Repurchase Obligation Waiver caused the elimination of the
HCDS revenues and expenses from our consolidated results
of operations beginning in November 2009. The revenues and
expenses
62
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
directly attributable to the HCDS for the periods prior to
November 2009 have been retrospectively reported as discontinued
operations based upon our decision not to purchase the system
from Quicksilver as follows:
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
Revenues
|
|
$
|
3,771
|
|
|
$
|
1,974
|
|
Operating Expenses
|
|
|
(3,718
|
)
|
|
|
(2,564
|
)
|
Interest Expense
|
|
|
(2,045
|
)
|
|
|
(1,740
|
)
|
|
|
|
|
|
|
|
|
|
Loss from discontinued operations
|
|
$
|
(1,992
|
)
|
|
$
|
(2,330
|
)
|
|
|
|
|
|
|
|
|
|
|
|
5.
|
PROPERTY,
PLANT AND EQUIPMENT
|
Property, plant and equipment consist of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
Depreciable Life
|
|
|
2010
|
|
|
2009
|
|
|
|
|
|
|
(In thousands)
|
|
|
Gathering systems
|
|
|
20 years
|
|
|
$
|
158,975
|
|
|
$
|
145,457
|
|
Processing plants and compression facilities
|
|
|
20-25 years
|
|
|
|
365,208
|
|
|
|
332,053
|
|
Construction in progress gathering
|
|
|
|
|
|
|
26,385
|
|
|
|
5,630
|
|
Rights-of-way
and easements
|
|
|
20 years
|
|
|
|
32,054
|
|
|
|
29,522
|
|
Land
|
|
|
|
|
|
|
4,251
|
|
|
|
4,251
|
|
Buildings and other
|
|
|
20-40 years
|
|
|
|
3,494
|
|
|
|
2,732
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
590,367
|
|
|
|
519,645
|
|
Accumulated depreciation
|
|
|
|
|
|
|
(58,996
|
)
|
|
|
(37,148
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
|
|
|
$
|
531,371
|
|
|
$
|
482,497
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6.
|
ACCOUNTS
PAYABLE AND OTHER
|
Accounts payable and other consists of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Accrued operating expenses
|
|
$
|
758
|
|
|
$
|
204
|
|
Equity compensation payable
|
|
|
|
|
|
|
242
|
|
Equity offering expense
|
|
|
|
|
|
|
416
|
|
Tax services
|
|
|
|
|
|
|
236
|
|
Tax payable
|
|
|
280
|
|
|
|
|
|
Legal services
|
|
|
176
|
|
|
|
376
|
|
Consulting services
|
|
|
802
|
|
|
|
|
|
Interest payable
|
|
|
726
|
|
|
|
660
|
|
Other
|
|
|
175
|
|
|
|
106
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,917
|
|
|
$
|
2,240
|
|
|
|
|
|
|
|
|
|
|
63
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table summarizes our long-term debt payments due
by period:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
|
(In thousands)
|
|
|
Credit Facility
|
|
$
|
283,504
|
|
|
$
|
125,400
|
|
Subordinated Note
|
|
|
|
|
|
|
55,718
|
|
|
|
|
|
|
|
|
|
|
|
|
|
283,504
|
|
|
|
181,118
|
|
Current maturities of debt
|
|
|
|
|
|
|
(2,475
|
)
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
283,504
|
|
|
$
|
178,643
|
|
|
|
|
|
|
|
|
|
|
Credit Facility As a result of the
Crestwood Transaction our old credit facility terminated and we
entered into our new five-year senior secured revolving Credit
Facility. Our new Credit Facility allows for revolving loans,
letters of credit and swingline loans in an aggregate amount of
up to $400 million. The new Credit Facility is secured by
substantially all of CMLPs and its subsidiaries
assets and is guaranteed by CMLPs subsidiaries. Borrowings
under the new Credit Facility bear interest at LIBOR plus an
applicable margin or a base rate as defined in the credit
agreement. Under the terms of the new Credit Facility, the
applicable margin under LIBOR borrowings is 2.75%.
Our new Credit Facility requires us to maintain:
|
|
|
|
|
a ratio of our consolidated trailing
12-month
EBITDA (as defined in the credit agreement) to our net interest
expense of not less than 2.5 to 1.0, and
|
|
|
|
a ratio of total indebtedness to consolidated trailing
12-month
EBITDA of not more than 5.0 to 1.0 or not more than 5.5 to 1.0
for up to nine months following certain acquisitions. (as
defined in the Credit Facility)
|
Our new Credit Facility also contains certain other customary
affirmative and negative covenants that could restrict the
payment of distributions and permit the acceleration of
outstanding borrowings by the lenders upon events of default.
Our new Credit Facility permits us to expand our borrowing
capacity up to $500 million if certain financial ratios are
obtained and we seek and receive lender approval.
Based on our results through December 31, 2010, our total
borrowing capacity was $393 million and our borrowings were
$283.5 million. The weighted-average interest rate as of
December 31, 2010 was 3.1%. The Credit Facility contains
restrictive covenants that prohibit the declaration or payment
of distributions by us if a default then exists or would result
therefrom, and otherwise limits the amount of distributions that
we can make. Upon an event of default, the Credit Facility
allows for the acceleration of the loans, the termination of the
Credit Facility and foreclosure on collateral.
Subordinated Note In August 2007, we
executed a subordinated promissory note (the Subordinated
Note) payable to Quicksilver in the principal amount of
$50.0 million.
Our new Credit Facility required us to terminate the
Subordinated Note through the issuance of additional common
units during the fourth quarter of 2010. The conversion into
common units was determined based upon the average closing
common unit price for a 20
trading-day
period that ended October 15, 2010. The conversion of the
Subordinated Note was unanimously approved by the conflicts
committee of our General Partners board of directors and
resulted in the issuance of 2,333,712 of our common units in
exchange for the outstanding balance of the Subordinated Note at
the time of the conversion.
64
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
8.
|
ASSET
RETIREMENT OBLIGATIONS
|
The following table provides a reconciliation of the changes in
the asset retirement obligation:
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31, 2010
|
|
|
|
(In thousands)
|
|
|
Adjusted asset retirement obligations at December 31, 2009
|
|
$
|
8,919
|
|
Incremental liability incurred
|
|
|
447
|
|
Accretion expense
|
|
|
511
|
|
|
|
|
|
|
Ending asset retirement obligations
|
|
$
|
9,877
|
|
|
|
|
|
|
As of December 31, 2010, no assets are legally restricted
for use in settling asset retirement obligations.
|
|
9.
|
COMMITMENTS
AND CONTINGENT LIABILITIES
|
Litigation At December 31, 2010, we were
not subject to any material lawsuits or other legal proceedings.
Casualties or Other Risks We maintain
coverage in various insurance programs, which provide us with
property damage and other coverages which are customary for the
nature and scope of our operations.
Management of our General Partner believes that we have adequate
insurance coverage, although insurance will not cover every type
of loss that might occur. As a result of insurance market
conditions, premiums and deductibles for certain insurance
policies have increased substantially and, in some instances,
certain insurance may become unavailable, or available for only
reduced amounts of coverage. As a result, we may not be able to
renew existing insurance policies or procure other desirable
insurance on commercially reasonable terms, if at all.
If we were to incur a significant loss for which we were not
adequately insured, the loss could have a material impact on our
consolidated financial condition and results of operations and
cash flows. In addition, the proceeds of any available insurance
may not be paid in a timely manner and may be insufficient if
such an event were to occur. Any event that interrupts our
revenues, or which causes us to make significant expenditures
not covered by insurance, could reduce our ability to meet our
financial obligations.
Regulatory Compliance In the ordinary course
of our business, we are subject to various laws and regulations.
In the opinion of management of our General Partner, compliance
with current laws and regulations will not have a material
adverse effect on our financial condition or results of
operations and cash flows.
Environmental Compliance Our operations are
subject to stringent and complex laws and regulations pertaining
to health, safety, and the environment. As an owner or operator
of these facilities, we are subject to laws and regulations at
the federal, state and local levels that relate to air and water
quality, hazardous and solid waste management and disposal and
other environmental matters. The cost of planning, designing,
constructing and operating our facilities must incorporate
compliance with environmental laws and regulations and safety
standards. Failure to comply with these laws and regulations may
trigger a variety of administrative, civil and potentially
criminal enforcement measures. At December 31, 2010, we had
recorded no liabilities for environmental matters.
65
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Commitments The following table summarizes
our commitment obligations:
|
|
|
|
|
|
|
|
|
|
|
Pipeline
|
|
|
Operating
|
|
|
|
Lease(1)
|
|
|
Lease(2)
|
|
|
|
(In thousands)
|
|
|
2011
|
|
$
|
0.8
|
|
|
$
|
0.8
|
|
2012
|
|
|
|
|
|
|
0.8
|
|
2013
|
|
|
|
|
|
|
0.7
|
|
2014
|
|
|
|
|
|
|
0.5
|
|
2015
|
|
|
|
|
|
|
0.4
|
|
Thereafter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
0.8
|
|
|
$
|
3.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
With the purchase of the Alliance Midstream Assets, we also
entered into an agreement with Quicksilver to lease pipeline
assets that are attached to the Alliance System. |
|
(2) |
|
We lease office buildings and other property under operating
leases. |
No provision for federal income taxes is included in our results
of operations as such income is taxable directly to the partners
holding interests in us. Net earnings for financial statement
purposes may differ significantly from taxable income reportable
to Unitholders as a result of differences between the tax basis
and financial reporting basis of assets and liabilities.
Prior to the closing of the Crestwood Transaction our activity
had been included in Quicksilvers Texas Franchise tax
combined report. As a member of the combined group, we could
subtract from revenue allowable cost of goods sold because the
goods for which the cost are incurred were owned by another
member of the combined group. There was also a deferred tax
portion recorded on the books each year to reflect the change in
book basis and tax basis. Quicksilver does not expect to owe
consolidated Texas margin tax for 2010, and accordingly, we do
not expect to make cash payment for our liability through
September 30, 2010, based upon the Texas margin tax filing
rules. All effects of the Texas margin tax were captured in
deferred income taxes through September 30, 2010, which
reflected temporary differences between the financial statement
assets and liabilities and their tax basis.
Effective with the closing of the Crestwood Transaction, we are
no longer included in Quicksilvers Texas Franchise tax
combined report and we will file a separate report under
Crestwood. Therefore, our current tax liability will be assessed
based on 0.7% of the gross revenue apportioned to Texas.
The closing of the Crestwood Transaction caused a technical
termination of CMLP as defined by the Internal Revenue Code. One
of the significant consequences of a technical termination is
its impact on the partnerships filing requirement for
federal income tax purposes. Generally, the partnership taxable
year closes with respect to all partners on the date on which a
partnership terminates. A terminated partnership must file a
federal income tax return for the short period ending on the
date of the sale that resulted in the technical termination. A
second short period return is then required to be filed for the
remainder of the taxable year of that new partnership. Our tax
status is, however, unaffected by these filings and the
technical termination. We do not expect to recognize a deferred
tax liability related to the Texas margin tax under our current
organizational structure.
66
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Awards of phantom units have been granted under our 2007 Equity
Plan which, as of December 31, 2010, had capacity for the
issuance of up to 750,000 remaining units. The following table
summarizes information regarding the phantom unit activity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payable in Cash
|
|
|
Payable in Units
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average Grant
|
|
|
|
|
|
Average Grant
|
|
|
|
|
|
|
Date Fair
|
|
|
|
|
|
Date Fair
|
|
|
|
Units
|
|
|
Value
|
|
|
Units
|
|
|
Value
|
|
|
Unvested phantom units January 1, 2010
|
|
|
33,240
|
|
|
$
|
20.90
|
|
|
|
485,672
|
|
|
$
|
12.75
|
|
Vested
|
|
|
(33,240
|
)
|
|
|
21.64
|
|
|
|
(695,582
|
)
|
|
|
15.29
|
|
Issued
|
|
|
|
|
|
|
|
|
|
|
338,003
|
|
|
|
23.38
|
|
Cancelled
|
|
|
|
|
|
|
|
|
|
|
(6,567
|
)
|
|
|
24.44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unvested phantom units December 31, 2010
|
|
|
|
|
|
$
|
|
|
|
|
121,526
|
|
|
$
|
27.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At January 1, 2010, we had total unvested compensation
expense of $2.9 million related to phantom units. We
recognized compensation expense of approximately
$6.4 million during 2010, including $0.3 million
related to Quicksilver equity grants issued to employees
seconded to us. Grants of phantom units during 2010 had an
estimated grant date fair value of $7.9 million. We had
unearned compensation expense of $2.6 million at
December 31, 2010 that will be recognized in expense
through January 2014. Phantom units that vested during 2010 had
a fair value of $11.4 million on their vesting date.
On January 4, 2010, we awarded annual equity grants
totaling 211,600 phantom units to the non-management directors,
executive officers of our General Partner and employees seconded
to us. Each phantom unit settled in CMLP units and had a grant
date value of $21.15, which were generally expected to be
recognized over the vesting period of three years except for
grants to non-employee directors of our General Partner in lieu
of cash compensation, which vest after one year. As a result of
the Crestwood Transaction, during the fourth quarter we
recognized compensation expense of approximately
$3.6 million, resulting in 523,011 units vesting and
347,888 units issued after the effect of taxes paid, which
is attributable to the acceleration of CMLPs equity-based
compensation program resulting from the
change-in-control
of provisions of our 2007 Equity Plan. This affected all
outstanding units and results in there being no unvested units
outstanding immediately thereafter.
On December 10, 2010, we awarded annual equity grants
totaling 126,403 phantom units to the executive officers of our
General Partner and employees of Crestwood. Each phantom unit
settled in CMLP units and had a grant date fair value of $27.11,
which will be recognized over the vesting period of three years
except for grants to non-employee directors of our General
Partner in lieu of cash compensation, which vest after one year.
At December 31, 2009 and 2010, respectively, 750,000 and
640,480 units were available for issuance under the 2007
Equity Plan.
On January 3, 2011, in accordance with our annual
compensation, we awarded director grants totaling 18,391 phantom
units. Each phantom unit will settle in units and had a grant
date value of $27.73.
|
|
12.
|
TRANSACTIONS
WITH RELATED PARTIES
|
Quicksilver remains a related party as Thomas F. Darden, a
member of our General Partners board of directors, is
Chairman of the Board of Quicksilver and beneficially holds a
greater than 10% interest in Quicksilver.
67
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Prior to, or in connection with, our IPO, we entered into a
number of agreements with Quicksilver. A description of those
agreements follows:
Contribution, Conveyance and Assumption
Agreement On August 10, 2007, we entered
into a contribution, conveyance, and assumption agreement
(Contribution Agreement) with our General Partner,
certain other affiliates of Quicksilver and the private
investors. The following transactions, among others, occurred
just prior to the IPO pursuant to the Contribution Agreement:
|
|
|
|
|
the transfer to us of all of the interests of certain entities;
|
|
|
|
the issuance of the incentive distribution rights to our General
Partner and the continuation of its 2% general partner interest
in us;
|
|
|
|
our issuance of 5,696,752 common units, 11,513,625 subordinated
units and the right to receive $162.1 million, to
Quicksilver in exchange for the contributed interests; and
|
|
|
|
our issuance of 816,873 common units and the right to receive
$7.7 million to private investors in exchange for their
contributed interests.
|
Omnibus Agreement On August 10, 2007, we
entered into an agreement with our General Partner and
Quicksilver, which addressed, among other matters:
|
|
|
|
|
restrictions on Quicksilvers ability to engage in
midstream activities in Quicksilver Counties;
|
|
|
|
Quicksilvers and our rights and obligations related to the
LADS and the HCDS;
|
|
|
|
our obligation to reimburse Quicksilver for all general and
administrative expenses incurred by Quicksilver on our behalf;
|
|
|
|
our obligation to reimburse Quicksilver for all insurance
coverage expenses Quicksilver incurs or payments it makes with
respect to our assets; and
|
|
|
|
Quicksilvers obligation to indemnify us for certain
liabilities and our obligation to indemnify Quicksilver for
certain liabilities.
|
This omnibus agreement with Quicksilver was terminated upon
completion of the Crestwood Transaction.
In October 2010, a new Omnibus Agreement was entered into among
our General Partner and Crestwood Holdings.
Secondment Agreement Quicksilver and our
General Partner had a services and secondment agreement pursuant
to which specified employees of Quicksilver had been seconded to
our General Partner to provide operating, routine maintenance
and other services with respect to the assets owned or operated
by us. We reimbursed Quicksilver for the services provided by
the seconded employees. Through September 30, 2010, we
reimbursed Quicksilver $7.6 million for the services
provided by the seconded employees. The Secondment Agreement was
terminated with Quicksilver upon completion of the Crestwood
Transaction.
Other Agreements On August 10, 2007, we
executed a subordinated promissory note payable to Quicksilver
in the principal amount of $50 million. Our new Credit
Facility required us to terminate the Subordinated Note that had
been payable to Quicksilver through the issuance of additional
common units during the fourth quarter of 2010. For a more
detailed description of the promissory note, see Note 7.
With the purchase of the Alliance Midstream Assets, we also
entered into an agreement with Quicksilver to lease pipeline
assets attached to the Alliance System. We recognized
$2.2 million of expense related to this agreement during
2010.
Centralized cash management Prior to our IPO,
revenues settled with Quicksilver and other customers, net of
expenses paid by Quicksilver on behalf of our Predecessor, are
reflected as partners capital activity on the
68
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
consolidated balance sheets and as a reduction of net cash
provided by financing activities on the consolidated statements
of cash flows. Subsequent to the IPO, revenues settled and
expenses paid on our behalf and are settled in cash on a monthly
basis utilizing our bank accounts.
Distributions We paid distributions to
Quicksilver of $30.3 million, $27.0 million and
$23.3 million during 2010, 2009 and 2008, respectively.
Allocation of costs Prior to the closing of
the Crestwood Transaction, the individuals supporting our
operations were employees of Quicksilver. Our consolidated
financial statements included costs allocated to us by
Quicksilver for centralized general and administrative services
performed by Quicksilver, as well as depreciation of assets
utilized by Quicksilvers centralized general and
administrative functions. Costs allocated to us were based on
identification of Quicksilvers resources which directly
benefited us and our estimated usage of shared resources and
functions. All of the allocations were based on assumptions that
management believed were reasonable.
For the years ended 2010, 2009 and 2008 general administration
expense includes cost allocated from Quicksilver of
$2.0 million, $2.8 million and $2.4 million,
respectively.
Gas Gathering and Processing Agreements
Quicksilver has agreed to dedicate all of the natural gas
produced on properties operated by Quicksilver within the areas
served by our Alliance Midstream Assets, Cowtown System and LADS
through 2020. These dedications do not obligate Quicksilver to
develop the reserves subject to these agreements.
Cowtown System Effective
September 1, 2008, we, together with Quicksilver, revised
the previous agreement by specifying that Quicksilver has agreed
to pay a fee per MMBtu for gathering, processing and compression
of gas on the Cowtown System. The compression fee payable by
Quicksilver at a gathering system delivery point shall never be
less than our actual cost to perform such compression service.
Quicksilver may also pay us a treating fee based on carbon
dioxide content at the pipeline entry point. The rates are each
subject to an annual inflationary escalation. During 2010, we
recognized $62.4 million related to this agreement.
During 2009, we entered into an agreement with Quicksilver to
redeliver gas from the Cowtown Plant to a group of wells located
near the facility. We recognized $0.8 million in revenue
during 2010 related to this agreement.
Lake Arlington Dry System During the
fourth quarter of 2008, we completed the acquisition of the LADS
from Quicksilver for $42.1 million. In conjunction with the
purchase, Quicksilver assigned its gas gathering agreement to
us. Under the terms of that agreement, Quicksilver agreed to
allow us to gather all of the natural gas produced by wells that
it operated and from future wells operated by it within the Lake
Arlington area through 2020. Quicksilvers fee is subject
to annual inflationary escalation. During 2010, we recognized
$14.5 million related to this agreement.
Alliance Midstream Assets In June
2009, we entered into an agreement with Quicksilver by which we
waived our right to purchase midstream assets located in and
around the Alliance Airport area in Tarrant County, Texas. The
agreement permitted Quicksilver to own and operate the Alliance
Midstream Assets and granted us an option to purchase the
Alliance Midstream Assets and additional midstream assets
located in Denton and Tarrant County, Texas. During January
2010, we completed the purchase of the Alliance Midstream Assets
for $84.4 million, located in Tarrant and Denton Counties
from Quicksilver. The acquired assets consist of gathering
systems and a compression facility with a total capacity of
115 MMcfd, an amine treating facility with capacity of
180 MMcfd and a dehydration treating facility with capacity
of 200 MMcfd. Under the terms of that agreement,
Quicksilver agreed to allow us to gather all of the natural gas
produced by wells that it operated and from future wells
operated by it within the Alliance area through 2020. The
gathering fee paid by Quicksilver is $0.55 per Mcf based on
volumes. During 2010, we recognized $27.5 million related
to this agreement.
Hill County Dry System In November
2009, Quicksilver and our General Partner mutually agreed to
waive both parties rights and obligations to transfer
ownership of the HCDS from Quicksilver to us, which we refer to
as
69
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
the Repurchase Obligation Waiver. The Repurchase Obligation
Waiver caused derecognition of the assets and liabilities
directly attributable to the HCDS, most significantly the
property, plant and equipment and repurchase obligation,
beginning in November 2009. The difference of $8.9 million
between the assets carrying values and the liabilities was
reflected as an increase in partners capital effective
upon the decision not to purchase. In addition, the Repurchase
Obligation Waiver caused the elimination of the HCDS
revenues and expenses from our consolidated results of
operations beginning in November 2009. The revenues and expenses
directly attributable to the HCDS for the period prior to
November 2009 have been retrospectively reported as discontinued
operations. We operate the HCDS pursuant to an operating
agreement between Quicksilver and us effective as of the
Crestwood Transaction. During 2010, we recognized $0.1 million
related to this agreement.
See Note 1 regarding amendments to gas gathering and
processing contracts that were effective upon completion of the
Crestwood Transaction.
Crestwood Transaction The Crestwood
Transaction was funded by an equity contribution from funds
managed by First Reserve and a $180 million senior secured
Term B loan obtained by Crestwood Holdings payable to multiple
financial investors. Crestwood Holdings ownership in us is
pledged as collateral and is dependent on distributions from us
to service the debt obligation which is not included in our
financial position.
Under the agreements governing the Crestwood Transaction,
Quicksilver and Crestwood have agreed for two years not to
solicit each others employees and Quicksilver has agreed
not to compete with us with respect to gathering, treating and
processing of natural gas and the transportation of natural gas
liquids in Denton, Hood, Somervell, Johnson, Tarrant, Parker,
Bosque and Erath Counties in Texas. Quicksilver is entitled to
appoint a director to our General Partners board of
directors until the later of the second anniversary of the
closing and such time as Quicksilver generates less than 50% of
our consolidated revenue in any fiscal year. Pursuant to this
provision, Thomas Darden, our former CEO, was appointed to serve
on our General Partners board of directors. The
independent directors continue to serve as directors after the
closing of the Crestwood Transaction.
In connection with the closing of the Crestwood Transaction,
Quicksilver is providing us with transitional services on a
temporary basis on customary terms. More than 100 experienced
midstream employees who had previously been seconded to us from
Quicksilver became employees of Crestwood. We also entered into
an agreement with Quicksilver for the joint development of areas
governed by certain of our existing commercial agreements and
amended certain of our existing commercial agreements, most
significantly to extend the terms of all Quicksilver gathering
agreements to 2020 and to establish a fixed gathering rate of
$0.55 Mcf at the Alliance System. During 2010, we have
recognized $0.4 million related to the transitional
services agreement and $0.2 million related to the joint
operating agreement.
|
|
13.
|
PARTNERS
CAPITAL AND DISTRIBUTIONS
|
General. Our Partnership Agreement requires
that we distribute all of our Available Cash (discussed below)
to unitholders within 45 days after the end of each
calendar quarter.
Available Cash, for any quarter, consists of all cash and cash
equivalents on hand at the end of that quarter plus additional
cash on hand on the date of determination of Available Cash for
the quarter resulting from working capital borrowings made
subsequent to the end of the quarter less the amount of cash
reserves established by the General Partner to:
|
|
|
|
|
provide for the proper conduct of our business;
|
|
|
|
comply with applicable law, any of our debt instruments or other
agreements; or
|
|
|
|
provide funds for distributions to partners for the succeeding
four quarters.
|
70
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table presents cash distributions for 2010 and
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Cash
|
|
|
|
Attributable to The
|
|
Per Unit
|
|
|
Distribution
|
|
Payment Date
|
|
Quarter Ended
|
|
Distribution(1)
|
|
|
(In millions)
|
|
|
Pending Distributions
|
|
|
|
|
|
|
|
|
|
|
February 11, 2011(2)
|
|
December 31, 2010
|
|
$
|
0.430
|
|
|
$
|
14.3
|
|
Completed Distributions
|
|
|
|
|
|
|
|
|
|
|
November 12, 2010(3)
|
|
September 30, 2010
|
|
$
|
0.420
|
|
|
$
|
13.9
|
|
August 13, 2010(4)
|
|
June 30, 2010
|
|
$
|
0.420
|
|
|
$
|
12.7
|
|
May 14, 2010(5)
|
|
March 31, 2010
|
|
$
|
0.390
|
|
|
$
|
11.6
|
|
February 12, 2010(5)
|
|
December 31, 2009
|
|
$
|
0.390
|
|
|
$
|
11.6
|
|
November 13, 2009(6)
|
|
September 30, 2009
|
|
$
|
0.390
|
|
|
$
|
9.7
|
|
August 14, 2009(7)
|
|
June 30, 2009
|
|
$
|
0.370
|
|
|
$
|
9.1
|
|
May 15, 2009(7)
|
|
March 31, 2009
|
|
$
|
0.370
|
|
|
$
|
9.1
|
|
|
|
|
(1)
|
|
Represents common and subordinated
unitholders
|
|
(2)
|
|
Total cash distribution includes an
Incentive Distribution Rights amount of approximately $665,000
to the General Partner
|
|
(3)
|
|
Total cash distribution includes an
Incentive Distribution Rights amount of approximately $570,000
to the General Partner
|
|
(4)
|
|
Total cash distribution includes an
Incentive Distribution Rights amount of approximately $522,000
to the General Partner
|
|
(5)
|
|
Total cash distribution includes an
Incentive Distribution Rights amount of approximately $261,000
to the General Partner
|
|
(6)
|
|
Total cash distribution includes an
Incentive Distribution Rights amount of approximately $219,000
to the General Partner
|
|
(7)
|
|
Total cash distribution includes an
Incentive Distribution Rights amount of approximately $90,000 to
the General Partner
|
General Partner Interest and Incentive Distribution
Rights. Our General Partner is entitled to its
pro rata portion of all our quarterly distributions. Our General
Partner has the right, but not the obligation, to contribute a
proportionate amount of capital to maintain its initial 2%
interest. At December 31, 2010, our General Partners
interest has been reduced to 1.5% due to the issuance of
additional common units. The incentive distribution rights held
by the General Partner entitle it to receive increasing
percentages, up to a maximum of 48%, of distributions from
operating surplus in excess of pre-defined distribution targets.
Subordinated Units. Prior to October 1,
2010, Quicksilver held all of the subordinated units, which were
limited partner interests. Our Partnership Agreement provides
that, during the subordination period, the common units have the
right to receive quarterly distributions of $0.30 per unit plus
any arrearages from prior quarters before any distributions from
operating surplus may be made to the subordinated unit holders.
Furthermore, no arrearages will be paid on subordinated units.
The practical effect of the subordinated units is to create a
higher likelihood of distribution to the common unit holders
during the subordination period. Under the Partnership
Agreement, the subordination period would end, and the
subordinated units would convert to an equal number of common
units, when we have earned and paid at least $0.30 per quarter
on each common unit, subordinated unit and General Partner unit
for any three consecutive years. The subordination period would
also terminate automatically if the General Partner is removed
without cause and the units held by the General Partner and its
affiliates are not cast in favor of removal. Once the
subordination period ends, the common units will no longer be
entitled to arrearages.
Our new Credit Facility required us to terminate the
Subordinated Note that had been payable to Quicksilver through
the issuance of additional common units during the fourth
quarter of 2010. The conversion into common units was determined
based upon the average closing common unit price for a 20
trading-day
period that ended October 15, 2010. The conversion of the
Subordinated Note was unanimously approved by the conflicts
committee of our General Partners board of directors and
resulted in the issuance of 2,333,712 of our common units in
exchange for the outstanding balance of the Subordinated Note at
the time of the conversion.
71
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Subordinated Units Termination. Under the
terms of our partnership agreement and upon the payment of our
quarterly cash distribution to unitholders on November 12,
2010, our subordination period ended. As a result, our
11,513,625 subordinated units held by Crestwood converted into
common units on a one for one basis on November 15, 2010.
The conversion of the subordinated units did not impact the
amount of cash distributions paid. The conversion had no impact
on our calculation of net income per limited partner unit since
the subordinated units were previously included in our
historical net income per limited partner unit calculation.
Distributions of Available Cash to
Unitholders. During the subordination period and
assuming the absence of arrearages and the distributions of at
least $0.30 distributed per unit per quarter:
|
|
|
|
|
quarterly distributions of up to $.0345 per unit were first
allocable to the common unit holders and to the General Partner
at their pro rata ownership percentages and then to subordinated
unit holders in their pro rata ownership percentage.
|
|
|
|
quarterly distributions in excess of $.0345 per unit were
allocable in the same fashion as lesser distributions, except
that the General Partner is entitled to increasing percentages
of the distribution pursuant to the incentive distribution
rights.
|
On February 18, 2011, we entered into a Purchase and Sale
Agreement (the Frontier Purchase and Sale Agreement)
with Frontier Gas Services, LLC, a Delaware limited liability
company (Frontier), pursuant to which we agreed to
acquire midstream assets (the Frontier Assets) in
the Fayetteville Shale and the Granite Wash plays for a purchase
price of approximately $338 million, with an additional
$15 million to be paid to Frontier if certain operational
objectives are met within six-months of the closing date (the
Frontier Acquisition). The final purchase price is
payable in cash, and we expect to finance the purchase through a
combination of equity and debt as described below. Consummation
of the Frontier Acquisition is subject to customary closing
conditions and regulatory approval. There can be no assurance
that these closing conditions will be satisfied. We expect to
close the Frontier Acquisition in the second quarter of 2011.
On February 18, 2011, we entered into a Class C Unit
Purchase Agreement (the Class C Unit Purchase
Agreement) with the purchasers named therein (the
Class C Unit Purchasers) to sell approximately
6.2 million Class C Units in a private placement. The
negotiated purchase price for the Class C Units is $24.50
per unit, resulting in gross proceeds to us of approximately
$153 million. If the closing of the private placement is
after the record date for our first quarter 2011 distribution in
respect of our Common Units, the price per Class C Unit
will be reduced by such distribution, but the total purchase
price will remain $153 million, and the number of
Class C Units issued will be increased accordingly. We
intend to use the net proceeds from the private placement to
fund a portion of the purchase price for the Frontier
Acquisition. The private placement of the Class C Units
pursuant to the Class C Unit Purchase Agreement is being
made in reliance upon an exemption from the registration
requirements of the Securities Act pursuant to Section 4(2)
and Regulation D thereof. The closing of the private
placement is subject to certain conditions including
(i) the closing of the Frontier Acquisition, (ii) the
receipt of, or binding commitments to fund the Frontier
Acquisition through (A) equity proceeds of not less than
$150 million pursuant to the Class C Unit Purchase
Agreement, and (B) debt financing of not less than
$185 million from the issuance or incurrence of
(x) borrowings under our Credit Facility,
(y) borrowings under a bridge facility,
and/or
(z) senior unsecured notes, senior subordinated notes
and/or other
debt securities, with the weighted average total effective yield
for the aggregate of all debt in this item (ii)(B) to be no more
than 8.75%, (iii) the adoption of an amendment to our
Partnership Agreement to establish the terms of the Class C
Units, (iv) NYSE approval for listing of the Common Units
to be issued upon conversion of the Class C Units, and
(v) our filing of this annual report with the SEC.
In connection to the Class C Unit Purchase Agreement, we
have agreed to enter into a registration rights agreement with
the Class C Unit Purchasers (the Registration Rights
Agreement). Pursuant to the Registration Rights Agreement,
upon request of a Class C Unit holder, we will be required
to file a resale registration statement
72
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
to register (i) the Class C Units issued pursuant to
the Class C Unit Purchase Agreement, (ii) the Common
Units issuable upon conversion of the Class C Units issued,
(iii) any Class C Units issued in respect of the
Class C Units as a distribution in kind in lieu of cash
distributions and (iv) any Class C Units issued as
liquidated damages under the Registration Rights Agreement, as
soon as practicable after such request.
In connection with the proposed Frontier Acquisition, we
obtained a commitment from UBS Loan Finance LLC, UBS Securities
LLC, BNP Paribas, BNP Paribas Securities Corp., Royal Bank of
Canada, RBC Capital Markets, RBS Securities Inc. and the Royal
Bank of Scotland plc for senior unsecured bridge loans in an
aggregate amount up to $200 million (the Bridge
Loans). The commitment will expire upon the earliest to
occur of (i) the termination of the Frontier Purchase and
Sale Agreement in accordance with its own terms or
(ii) 90 days after February 18, 2011.
|
|
15.
|
CONDENSED
CONSOLIDATING FINANCIAL INFORMATION
|
Condensed consolidating financial information for CMLP is
presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
Crestwood
|
|
|
|
Crestwood
|
|
|
Restricted
|
|
|
|
|
|
Midstream
|
|
|
|
Midstream
|
|
|
Guarantor
|
|
|
|
|
|
Partners LP
|
|
|
|
Partners LP
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Revenue
|
|
$
|
|
|
|
$
|
113,590
|
|
|
$
|
|
|
|
$
|
113,590
|
|
Operating expenses
|
|
|
17,782
|
|
|
|
47,936
|
|
|
|
|
|
|
|
65,718
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
(17,782
|
)
|
|
|
65,654
|
|
|
|
|
|
|
|
47,872
|
|
Interest expense
|
|
|
13,550
|
|
|
|
|
|
|
|
|
|
|
|
13,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income tax
|
|
|
(31,332
|
)
|
|
|
65,654
|
|
|
|
|
|
|
|
34,322
|
|
Income tax provision
|
|
|
|
|
|
|
(550
|
)
|
|
|
|
|
|
|
(550
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before equity in net earnings of subsidiaries
|
|
|
(31,332
|
)
|
|
|
66,204
|
|
|
|
|
|
|
|
34,872
|
|
Equity in net earnings of subsidiaries
|
|
|
66,204
|
|
|
|
|
|
|
|
(66,204
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
34,872
|
|
|
$
|
66,204
|
|
|
$
|
(66,204
|
)
|
|
$
|
34,872
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Crestwood
|
|
|
|
Crestwood
|
|
|
Restricted
|
|
|
|
|
|
Midstream
|
|
|
|
Midstream
|
|
|
Guarantor
|
|
|
|
|
|
Partners LP
|
|
|
|
Partners LP
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Revenue
|
|
$
|
|
|
|
$
|
95,881
|
|
|
$
|
|
|
|
$
|
95,881
|
|
Operating expenses
|
|
|
9,636
|
|
|
|
42,837
|
|
|
|
|
|
|
|
52,473
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
(9,636
|
)
|
|
|
53,044
|
|
|
|
|
|
|
|
43,408
|
|
Other income
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Interest expense
|
|
|
6,838
|
|
|
|
1,681
|
|
|
|
|
|
|
|
8,519
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income tax
|
|
|
(16,473
|
)
|
|
|
51,363
|
|
|
|
|
|
|
|
34,890
|
|
Income tax provision
|
|
|
|
|
|
|
399
|
|
|
|
|
|
|
|
399
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations
|
|
|
(16,473
|
)
|
|
|
50,964
|
|
|
|
|
|
|
|
34,491
|
|
Income (loss) from discontinued operations
|
|
|
(1,992
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,992
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before equity in net earnings of subsidiaries
|
|
|
(18,465
|
)
|
|
|
50,964
|
|
|
|
|
|
|
|
32,499
|
|
Equity in net earnings of subsidiaries
|
|
|
50,964
|
|
|
|
|
|
|
|
(50,964
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
32,499
|
|
|
$
|
50,964
|
|
|
$
|
(50,964
|
)
|
|
$
|
32,499
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Crestwood
|
|
|
|
Crestwood
|
|
|
Restricted
|
|
|
|
|
|
Midstream
|
|
|
|
Midstream
|
|
|
Guarantor
|
|
|
|
|
|
Partners LP
|
|
|
|
Partners LP
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Revenue
|
|
$
|
|
|
|
$
|
76,084
|
|
|
$
|
|
|
|
$
|
76,084
|
|
Operating expenses
|
|
|
6,941
|
|
|
|
31,992
|
|
|
|
|
|
|
|
38,933
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
(6,941
|
)
|
|
|
44,092
|
|
|
|
|
|
|
|
37,151
|
|
Other income
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
11
|
|
Interest expense
|
|
|
4,153
|
|
|
|
4,284
|
|
|
|
|
|
|
|
8,437
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations before income tax
|
|
|
(11,083
|
)
|
|
|
39,808
|
|
|
|
|
|
|
|
28,725
|
|
Income tax provision
|
|
|
|
|
|
|
253
|
|
|
|
|
|
|
|
253
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from continuing operations
|
|
|
(11,083
|
)
|
|
|
39,555
|
|
|
|
|
|
|
|
28,472
|
|
Income (loss) from discontinued operations
|
|
|
(2,330
|
)
|
|
|
|
|
|
|
|
|
|
|
(2,330
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before equity in net earnings of subsidiaries
|
|
|
(13,413
|
)
|
|
|
39,555
|
|
|
|
|
|
|
|
26,142
|
|
Equity in net earnings of subsidiaries
|
|
|
39,555
|
|
|
|
|
|
|
|
(39,555
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
26,142
|
|
|
$
|
39,555
|
|
|
$
|
(39,555
|
)
|
|
$
|
26,142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
74
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Condensed
Consolidated Balance Sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
Crestwood
|
|
|
|
Crestwood
|
|
|
Restricted
|
|
|
|
|
|
Midstream
|
|
|
|
Midstream
|
|
|
Guarantor
|
|
|
|
|
|
Partners LP
|
|
|
|
Partners LP
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets
|
|
$
|
291,637
|
|
|
$
|
23,843
|
|
|
$
|
(289,744
|
)
|
|
$
|
25,736
|
|
Properties, plant and equipment net
|
|
|
11,142
|
|
|
|
520,229
|
|
|
|
|
|
|
|
531,371
|
|
Investment in subsidiaries
|
|
|
228,587
|
|
|
|
|
|
|
|
(228,587
|
)
|
|
|
|
|
Other assets
|
|
|
12,890
|
|
|
|
630
|
|
|
|
|
|
|
|
13,520
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
544,256
|
|
|
$
|
544,702
|
|
|
$
|
(518,331
|
)
|
|
$
|
570,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current liabilities
|
|
$
|
1,999
|
|
|
$
|
306,238
|
|
|
$
|
(289,744
|
)
|
|
$
|
18,493
|
|
Long-term liabilities
|
|
|
283,504
|
|
|
|
9,877
|
|
|
|
|
|
|
|
293,381
|
|
Partners capital
|
|
|
258,753
|
|
|
|
228,587
|
|
|
|
(228,587
|
)
|
|
|
258,753
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
544,256
|
|
|
$
|
544,702
|
|
|
$
|
(518,331
|
)
|
|
$
|
570,627
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Crestwood
|
|
|
|
Crestwood
|
|
|
Restricted
|
|
|
|
|
|
Midstream
|
|
|
|
Midstream
|
|
|
Guarantor
|
|
|
|
|
|
Partners LP
|
|
|
|
Partners LP
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
ASSETS
|
Current assets
|
|
$
|
173,307
|
|
|
$
|
1,521
|
|
|
$
|
(172,560
|
)
|
|
$
|
2,268
|
|
Properties, plant and equipment net
|
|
|
|
|
|
|
482,497
|
|
|
|
|
|
|
|
482,497
|
|
Investment in subsidiaries
|
|
|
292,439
|
|
|
|
|
|
|
|
(292,439
|
)
|
|
|
|
|
Other assets
|
|
|
2,194
|
|
|
|
665
|
|
|
|
|
|
|
|
2,859
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
467,940
|
|
|
$
|
484,683
|
|
|
$
|
(464,999
|
)
|
|
$
|
487,624
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND PARTNERS CAPITAL
|
Current liabilities
|
|
$
|
4,461
|
|
|
$
|
182,556
|
|
|
$
|
(172,560
|
)
|
|
$
|
14,457
|
|
Long-term liabilities
|
|
|
178,642
|
|
|
|
9,688
|
|
|
|
|
|
|
|
188,330
|
|
Partners capital
|
|
|
284,837
|
|
|
|
292,439
|
|
|
|
(292,439
|
)
|
|
|
284,837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
467,940
|
|
|
$
|
484,683
|
|
|
$
|
(464,999
|
)
|
|
$
|
487,624
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75
CRESTWOOD
MIDSTREAM PARTNERS LP
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Condensed
Consolidated Statement of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
Crestwood
|
|
|
|
Crestwood
|
|
|
Restricted
|
|
|
|
|
|
Midstream
|
|
|
|
Midstream
|
|
|
Guarantor
|
|
|
|
|
|
Partners LP
|
|
|
|
Partners LP
|
|
|
Subsidiaries
|
|
|
Eliminations
|
|
|
Consolidated
|
|
|
|
(In thousands)
|
|
|
Net cash (used in) provided by operating activities
|
|
$
|
(23,588
|
)
|
|
$
|
71,591
|
|
|
$
|
|
|
|
$
|
48,003
|
|
Capital expenditures
|
|
|
(11,079
|
)
|
|
|
(57,990
|
)
|
|
|
|
|
|
|
(69,069
|
)
|
Distributions to Quicksilver for Alliance Midstream Assets
|
|
|
|
|
|
|
(80,276
|
)
|
|
|
|
|
|
|
(80,276
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(11,079
|
)
|
|
|
(138,266
|
)
|
|
|
|
|
|
|
(149,345
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from revolving credit facility borrowings
|
|
|
426,704
|
|
|
|
|
|
|
|
|
|
|
|
426,704
|
|
Repayments of credit facility
|
|
|
(268,600
|
)
|
|
|
|
|
|
|
|
|
|
|
(268,600
|
)
|
Debt issuance costs paid
|
|
|
(13,568
|
)
|
|
|
|
|
|
|
|
|
|
|
(13,568
|
)
|
Proceeds from issuance of equity
|
|
|
11,088
|
|
|
|
|
|
|
|
|
|
|
|
11,088
|
|
Equity issuance cost paid
|
|
|
(34
|
)
|
|
|
|
|
|
|
|
|
|
|
(34
|
)
|
Distributions to unitholders
|
|
|
(49,699
|
)
|
|
|
|
|
|
|
|
|
|
|
(49,699
|
)
|
Taxes paid for equity-based compensation vesting
|
|
|
(5,293
|
)
|
|
|
|
|
|
|
|
|
|
|
(5,293
|
)
|
Advances to Affiliates
|
|
|
117,184
|
|
|
|
(117,184
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
217,782
|
|
|
|
(117,184
|
)
|
|
|
|
|
|
|
100,598
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash increase (decrease)
|
|
|
183,115
|
|
|
|
(183,859
|
)
|
|
|
|
|
|
|
(744
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
746
|
|
|
|
|
|
|
|
|
|
|
|
746
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
183,861
|
|
|
$
|
(183,859
|
)
|
|
$
|
|
|
|
$
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|