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EX-23.1 - EX-23.1 - Crestwood Midstream Partners LPh79688exv23w1.htm
EX-31.1 - EX-31.1 - Crestwood Midstream Partners LPh79688exv31w1.htm
EX-31.2 - EX-31.2 - Crestwood Midstream Partners LPh79688exv31w2.htm
EX-32.1 - EX-32.1 - Crestwood Midstream Partners LPh79688exv32w1.htm
EX-10.6 - EX-10.6 - Crestwood Midstream Partners LPh79688exv10w6.htm
EX-10.26 - EX-10.26 - Crestwood Midstream Partners LPh79688exv10w26.htm
EX-10.24 - EX-10.24 - Crestwood Midstream Partners LPh79688exv10w24.htm
EX-10.18 - EX-10.18 - Crestwood Midstream Partners LPh79688exv10w18.htm
EX-10.23 - EX-10.23 - Crestwood Midstream Partners LPh79688exv10w23.htm
EX-10.28 - EX-10.28 - Crestwood Midstream Partners LPh79688exv10w28.htm
EX-10.22 - EX-10.22 - Crestwood Midstream Partners LPh79688exv10w22.htm
EX-10.27 - EX-10.27 - Crestwood Midstream Partners LPh79688exv10w27.htm
EX-10.25 - EX-10.25 - Crestwood Midstream Partners LPh79688exv10w25.htm
EX-10.16 - EX-10.16 - Crestwood Midstream Partners LPh79688exv10w16.htm
EX-10.20 - EX-10.20 - Crestwood Midstream Partners LPh79688exv10w20.htm
EX-21.1 - EX-21.1 - Crestwood Midstream Partners LPh79688exv21w1.htm
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
    SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2010
or
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
    SECURITIES EXCHANGE ACT OF 1934
    For the transition period from          to          
 
Commission file number: 001-33631
 
CRESTWOOD MIDSTREAM PARTNERS LP
(Exact name of registrant as specified in its charter)
 
     
Delaware
  56-2639586
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
717 Texas Avenue, Suite 3150, Houston, Texas
  77002
(Address of principal executive offices)
  (Zip Code)
 
(832) 519-2200
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of each class
 
Name of each exchange on which registered
 
Common Units of Limited Partner Interests   NYSE
 
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 registrant’s 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):
 
             
Large accelerated filer o
  Accelerated filer þ   Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller Reporting company o
 
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 registrant’s 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
 


Table of Contents

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 LP’s 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
 
                 
PART I
  ITEM 1.     Business     6  
  ITEM 1A.     Risk Factors     17  
  ITEM 1B.     Unresolved Staff Comments     33  
  ITEM 2.     Properties     33  
  ITEM 3.     Legal Proceedings     34  
  ITEM 4.     Reserved     34  
 
PART II
  ITEM 5.     Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     35  
  ITEM 6.     Selected Financial Data     37  
  ITEM 7.     Management’s Discussion and Analysis of Financial Condition and Results of Operations     39  
  ITEM 7A.     Quantitative and Qualitative Disclosures about Market Risk     50  
  ITEM 8.     Financial Statements and Supplementary Data     51  
  ITEM 9.     Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     78  
  ITEM 9A.     Controls and Procedures     78  
  ITEM 9B.     Other Information     80  
 
PART III
  ITEM 10.     Directors and Executive Officers and Corporate Governance     81  
  ITEM 11.     Executive Compensation     85  
  ITEM 12.     Security Ownership of Certain Management and Beneficial Owners and Management and Related Unitholder Matters     97  
  ITEM 13.     Certain Relationships and Related Transactions and Director Independence     98  
  ITEM 14.     Principal Accountant Fees and Services     102  
 
PART IV
  ITEM 15.     Exhibits and Financial Statement Schedules     103  
        Signatures     106  
 EX-10.6
 EX-10.16
 EX-10.18
 EX-10.20
 EX-10.22
 EX-10.23
 EX-10.24
 EX-10.25
 EX-10.26
 EX-10.27
 EX-10.28
 EX-21.1
 EX-23.1
 EX-31.1
 EX-31.2
 EX-32.1
 
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.


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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:
 
  •  changes in general economic conditions;
 
  •  fluctuations in natural gas prices;
 
  •  failure or delays by our customers in achieving expected production from natural gas projects;
 
  •  competitive conditions in our industry;
 
  •  actions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers;
 
  •  fluctuations in the value of certain of our assets and liabilities;
 
  •  changes in the availability and cost of capital;
 
  •  operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
 
  •  construction costs or capital expenditures exceeding estimated or budgeted amounts;
 
  •  the effects of existing and future laws and governmental regulations, including environmental and climate change requirements;
 
  •  the effects of existing or future litigation; and
 
  •  certain factors discussed elsewhere in this annual report.
 
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
 
  •  the acquisition may not be consummated;
 
  •  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;
 
  •  financing the acquisition will substantially increase our leverage;
 
  •  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;
 
  •  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;
 
  •  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
 
  •  we may experience disruption from the transaction making it more difficult to maintain relationships with customers, employees or suppliers.
 
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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Table of Contents

PART I
 
Item 1.   Business
 
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 1990’s, 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 Quicksilver’s 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:
 
  •  Crestwood’s purchase of a 100% interest in Crestwood Gas Services GP LLC, our General Partner
 
  •  5,696,752 common units and 11,513,625 subordinated units; and
 
  •  $58 million subordinated note payable by Crestwood Midstream Partners LP.
 
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:
 
  •  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;
 
  •  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 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.
 
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 Partner’s 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 CMLP’s and its subsidiaries’ assets and is guaranteed by CMLP’s subsidiaries.
 
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 %
                         
 
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:
 
  •  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.
 
  •  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.
 
  •  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.
 
  •  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.
 
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:
 
  •  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.
 
  •  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.
 
  •  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.
 
  •  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.
 
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:
 
  •  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.
 
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 System’s 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 Quicksilver’s 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 Quicksilver’s 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 FERC’s 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 EPA’s 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 EPA’s 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:
 
  •  requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of our wastes;
 
  •  limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;
 
  •  requiring investigatory and remedial actions to mitigate or eliminate pollution conditions caused by our operations or attributable to former operations; and
 
  •  enjoining the operations of facilities deemed to be in non-compliance with such environmental laws and regulations and permits issued pursuant thereto.
 
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 RCRA’s 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 SEC’s 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 SEC’s 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 Partner’s 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 Partner’s 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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Item 1A.   Risk Factors
 
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 Quicksilver’s 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:
 
  •  the fees we charge and the margins we realize for our services;
 
  •  the level of production, and the prices of, natural gas, NGLs, and condensate;
 
  •  the volume of natural gas and NGLs we gather and process;
 
  •  the level of competition from other midstream energy companies;
 
  •  the level of our operating and maintenance and general and administrative costs;
 
  •  prevailing economic conditions;
 
  •  the level of capital expenditures we make;
 
  •  our ability to make borrowings under our Credit Facility;
 
  •  the cost of acquisitions;


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  •  our debt service requirements;
 
  •  fluctuations in our working capital needs;
 
  •  our ability to access capital markets;
 
  •  compliance with our debt agreements; and
 
  •  the amount of cash reserves established by our General Partner.
 
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:
 
  •  mistaken assumptions about volumes, revenue and costs, including synergies;
 
  •  an inability to integrate successfully the assets we acquire;
 
  •  the assumption of unknown liabilities;
 
  •  limitations on rights to indemnity from the seller;
 
  •  mistaken assumptions about the overall costs of equity or debt;
 
  •  the diversion of management’s and employees’ attention from other business matters;
 
  •  unforeseen difficulties operating in new product areas, with new customers, or new geographic areas; and
 
  •  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:
 
  •  operational problems, labor difficulties or environmental proceedings or other litigation that compel curtailing of all or a portion of the operations;
 
  •  catastrophic events at our facilities or at downstream facilities owned by others;
 
  •  lack of transportation or fractionation capacity;
 
  •  an inability to obtain sufficient quantities of natural gas; or
 
  •  prolonged reductions in exploration or production activity by producers in the areas in which we operate.
 
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 Quicksilver’s wells to be shut-in (in the case of gathering) or resulting in Quicksilver’s 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. FERC’s 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


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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:
 
  •  perform ongoing assessments of pipeline integrity;
 
  •  identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
 
  •  maintain processes for data collection, integration and analysis;
 
  •  repair and remediate pipelines as necessary; and
 
  •  implement preventive and mitigating actions.
 
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:
 
  •  damage to pipelines and plants, related equipment and surrounding properties caused by natural disasters and acts of terrorism;
 
  •  inadvertent damage from construction, farm and utility equipment;
 
  •  leaks or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;
 
  •  fires and explosions; and
 
  •  other hazards that could also result in personal injury, loss of life, pollution or suspension of operations.
 
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:
 
  •  incur additional debt or guarantee other indebtedness;
 
  •  make distributions on, redeem or repurchase units;
 
  •  make certain investments and acquisitions;
 
  •  incur or permit certain liens to exist;
 
  •  enter into certain types of transactions with affiliates;
 
  •  merge, consolidate or amalgamate with another company; and
 
  •  transfer or otherwise dispose of assets.
 
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. Quicksilver’s 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 Quicksilver’s board of directors in which they expressed an interest in pursuing strategic alternatives for Quicksilver, including potentially taking Quicksilver’s equity interests private. Additionally, Quicksilver’s 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 Quicksilver’s 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 Quicksilver’s 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, Crestwood’s 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 Partner’s 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


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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 entity’s 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 Partner’s 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 Partner’s 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


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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 Crestwood’s 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 Partner’s 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 management’s 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:
 
  •  our existing unitholders’ proportionate ownership interest in us will decrease;
 
  •  the amount of cash available for distribution on each unit may decrease;
 
  •  the ratio of taxable income to distributions may increase;
 
  •  the relative voting strength of each previously outstanding unit may be diminished; and
 
  •  the market price of the common units may decline.
 
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:
 
  •  we were conducting business in a state but had not complied with the applicable limited partnership statute; or
 
  •  unitholder’s 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.
 
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; public’s 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:
 
  •  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;
 
  •  the performance by each party of its obligations under the Frontier Purchase and Sale Agreement; and
 
  •  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.
 
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:
 
  •  unexpected operational events;
 
  •  adverse weather conditions;
 
  •  regulatory hurdles;
 
  •  facility or equipment malfunctions or breakdowns;
 
  •  a shortage of skilled labor; and
 
  •  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


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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 unitholder’s share of our taxable income or even equal the actual tax liability that results from the unitholder’s 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 unitholder’s 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.
 
Item 2.   Properties
 
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.


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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.
 
Item 4.   Reserved


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PART II
 
Item 5.   Market For Registrant’s 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.


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Performance Graph
 
The following performance graph compares the cumulative total unitholder return on our common units with the Standard & Poor’s 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
 
LINE GRAPH


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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 Quicksilver’s 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.


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(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.


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ITEM 7.   Management’s 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 Crestwood’s 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 other’s 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 Partner’s 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 Partner’s board of directors. Our current independent directors continue to serve as directors after the closing of the Crestwood Transaction.


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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.


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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 Quicksilver’s 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:
 
  •  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
 
  •  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 company’s 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


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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:
 
  •  financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
 
  •  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
 
  •  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:
 
                         
    Year Ended December 31,  
    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
    70,231       64,237       50,282  
Other income
          1       11  
                         
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  
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  
                         
 
The following table summarizes our volumes for each of the three years ended December 31, 2010:
 
                                                 
    Gathering     Processing  
    2010     2009     2008     2010     2009     2008  
                (MMcf)              
 
Cowtown System
    47,275       55,337       57,550       46,660       54,386       56,225  
Lake Arlington Dry System
    26,854       23,132       13,067                    
Alliance Midstream Assets
    51,188       15,486                          
                                                 
Total
    125,317       93,955       70,617       46,660       54,386       56,225  
                                                 


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The following table summarizes the changes in our revenues:
 
                                 
    Gathering     Processing     Other     Total  
          (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  
Price changes
    3,497       436       (1,291 )     2,642  
                                 
Revenue for the year ended ended December 31, 2010
  $ 83,394     $ 30,196     $     $ 113,590  
                                 
 
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 Quicksilver’s 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


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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.
 
                 
    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 Quicksilver’s 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


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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 Quicksilver’s 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.


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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


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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.


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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.


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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 asset’s 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 asset’s 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.


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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. Quicksilver’s 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.


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Table of Contents

 
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 Company’s 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 Company’s 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 Company’s internal control over financial reporting.
 
/s/ Deloitte & Touche LLP
 
Fort Worth, Texas
February 25, 2011


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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.


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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.


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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.


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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.


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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 Crestwood’s 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 %
                         


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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


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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 System’s 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.


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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 asset’s 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 asset’s 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.


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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 Partner’s 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.


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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


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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  
                 


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CRESTWOOD MIDSTREAM PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
7.   LONG-TERM DEBT
 
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 CMLP’s and its subsidiaries’ assets and is guaranteed by CMLP’s 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 Partner’s 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.


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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.


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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.
 
10.   INCOME TAXES
 
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 Quicksilver’s 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 Quicksilver’s 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 partnership’s 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.


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CRESTWOOD MIDSTREAM PARTNERS LP
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
11.   EQUITY PLAN
 
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 CMLP’s 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 Partner’s board of directors, is Chairman of the Board of Quicksilver and beneficially holds a greater than 10% interest in Quicksilver.


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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 Quicksilver’s ability to engage in midstream activities in Quicksilver Counties;
 
  •  Quicksilver’s 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
 
  •  Quicksilver’s 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


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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 Quicksilver’s centralized general and administrative functions. Costs allocated to us were based on identification of Quicksilver’s 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. Quicksilver’s 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


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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 other’s 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 Partner’s 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 Partner’s 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.


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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 Partner’s 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 Partner’s 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.


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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.
 
14.   SUBSEQUENT 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


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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  
                                 
 


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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  
                                 

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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  
                                 


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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  
                                 
 
                                 
    For the Year Ended December 31, 2009  
                      Crestwood
 
    Crestwood
    Restricted
          Midstream
 
    Midstream
    Guarantor
          Partners LP
 
    Partners LP     Subsidiaries     Eliminations     Consolidated  
    (In thousands)  
 
Net cash (used in) provided by operating activities
  $ (10,972 )   $ 79,921     $  —     $ 68,949  
Capital expenditures
          (54,818 )           (54,818 )
                                 
Net cash used in investing activities
          (54,818 )           (54,818 )
                                 
Proceeds from revolving credit facility borrowings
    56,000                   56,000  
Repayments of credit facility
    (105,500 )                 (105,500 )
Repayment of repurchase obligation to Quicksilver
    (5,645 )                 (5,645 )
Debt issuance costs paid
    (1,446 )                 (1,446 )
Proceeds from issuance of equity
          80,760             80,760  
Equity issuance cost paid
    (31 )                 (31 )
Contributions by Quicksilver
    (816 )                 (816 )
Distributions to unitholders
    (36,947 )                 (36,947 )
Taxes paid for equity-based compensation vesting
    (63 )                 (63 )
Advances to Affiliates
    18,393