Crestwood Midstream Partners LP
Annual Report 2010

Plain-text annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ¥ n FORM 10-K 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 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 (State or other jurisdiction of incorporation or organization) 717 Texas Avenue, Suite 3150, Houston, Texas (Address of principal executive offices) 56-2639586 (I.R.S. Employer Identification No.) 77002 (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 n No ¥ 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 n No ¥ 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 ¥ No n 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 n No n 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. n 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 n Accelerated filer ¥ Smaller Reporting company n Non-accelerated filer n (Do not check if a smaller reporting company) Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes n No ¥ 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 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 2 6 17 33 33 34 34 35 37 39 50 51 78 78 80 81 85 INDEX TO ANNUAL REPORT ON FORM 10-K For the Year Ended December 31, 2010 PART I Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 1. ITEM 1A. Risk Factors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 2. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 3. Reserved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 4. PART II ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations . . ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 8. ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . ITEM 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART III ITEM 10. Directors and Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . ITEM 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 12. Security Ownership of Certain Management and Beneficial Owners and Management and Related Unitholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ITEM 13. Certain Relationships and Related Transactions and Director Independence . . . . . . . . . . . . . ITEM 14. 97 98 Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102 PART IV ITEM 15. Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103 Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106 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 subsid- iaries, excluding CMLP and Crestwood Gas Services GP LLC, our General Partner. 3 FORWARD-LOOKING INFORMATION Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “predict,” “strategy,” “expect,” “intend,” “plan,” “aim,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “con- tinue,” 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: (cid:129) changes in general economic conditions; (cid:129) fluctuations in natural gas prices; (cid:129) failure or delays by our customers in achieving expected production from natural gas projects; (cid:129) competitive conditions in our industry; (cid:129) actions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers; (cid:129) fluctuations in the value of certain of our assets and liabilities; (cid:129) changes in the availability and cost of capital; (cid:129) operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control; (cid:129) construction costs or capital expenditures exceeding estimated or budgeted amounts; (cid:129) the effects of existing and future laws and governmental regulations, including environmental and climate change requirements; (cid:129) the effects of existing or future litigation; and (cid:129) 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 (cid:129) the acquisition may not be consummated; (cid:129) 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; (cid:129) financing the acquisition will substantially increase our leverage; (cid:129) 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; (cid:129) 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; 4 (cid:129) the acquisition could expose us to additional unknown and contingent liabilities; (cid:129) 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 (cid:129) 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. 5 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: (cid:129) Crestwood’s purchase of a 100% interest in Crestwood Gas Services GP LLC, our General Partner (cid:129) 5,696,752 common units and 11,513,625 subordinated units; and (cid:129) $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.” 6 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: (cid:129) 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; (cid:129) acceleration of amounts due under our old $320 million credit facility, which was replaced with a new $400 million Credit Facility; (cid:129) termination of our omnibus agreement with Quicksilver, which was replaced with a new Omnibus Agreement; (cid:129) termination of our Services and Secondment Agreement with Quicksilver which we replaced with a Transition Services Agreement with Quicksilver; (cid:129) extension of the tenor of all of our gathering and processing agreements with Quicksilver to 2020; and (cid:129) 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: General partner interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Limited partner interest: Common unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ownership Percentage Crestwood Public Total 1.5% — 1.5% 61.7% 63.2% 36.8% 98.5% 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 7 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: (cid:129) 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. (cid:129) 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 8 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. (cid:129) 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. (cid:129) 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: (cid:129) 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. (cid:129) 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. (cid:129) 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. (cid:129) 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 9 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 Mid- stream 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: (cid:129) 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; (cid:129) 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 (cid:129) 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. 10 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. 11 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, environ- mental 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. Addi- tional 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 inspec- tions for all U.S. liquid and gas transportation pipelines and some gathering lines in high-population areas. 12 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 environ- mental 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: (cid:129) requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of our wastes; (cid:129) limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species; (cid:129) requiring investigatory and remedial actions to mitigate or eliminate pollution conditions caused by our operations or attributable to former operations; and (cid:129) 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. 13 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 14 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 15 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. 16 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 com- mon 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: (cid:129) the fees we charge and the margins we realize for our services; (cid:129) the level of production, and the prices of, natural gas, NGLs, and condensate; (cid:129) the volume of natural gas and NGLs we gather and process; (cid:129) the level of competition from other midstream energy companies; (cid:129) the level of our operating and maintenance and general and administrative costs; (cid:129) prevailing economic conditions; (cid:129) the level of capital expenditures we make; (cid:129) our ability to make borrowings under our Credit Facility; (cid:129) the cost of acquisitions; 17 (cid:129) our debt service requirements; (cid:129) fluctuations in our working capital needs; (cid:129) our ability to access capital markets; (cid:129) compliance with our debt agreements; and (cid:129) 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 distribu- tions, 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. There- fore, 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 devel- opment 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. 18 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, environ- mental, political, legal and economic risks, which could adversely affect our cash flows, results of opera- tions 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: (cid:129) mistaken assumptions about volumes, revenue and costs, including synergies; (cid:129) an inability to integrate successfully the assets we acquire; (cid:129) the assumption of unknown liabilities; (cid:129) limitations on rights to indemnity from the seller; (cid:129) mistaken assumptions about the overall costs of equity or debt; (cid:129) the diversion of management’s and employees’ attention from other business matters; (cid:129) unforeseen difficulties operating in new product areas, with new customers, or new geographic areas; and (cid:129) customer or key employee losses at the acquired businesses. 19 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: (cid:129) operational problems, labor difficulties or environmental proceedings or other litigation that compel curtailing of all or a portion of the operations; (cid:129) catastrophic events at our facilities or at downstream facilities owned by others; (cid:129) lack of transportation or fractionation capacity; (cid:129) an inability to obtain sufficient quantities of natural gas; or (cid:129) 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 20 restrict our right to decide whose production we gather. Federal law leaves any economic regulation of natural gas gathering to the states. Texas, the only state in which we currently operate, has adopted complaint-based regulation of gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve access and rate grievances. Other state and municipal regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the rates, terms and conditions of our gathering lines. We are subject to environmental laws, regulations and permits, including greenhouse gas requirements that may expose us to significant costs, liabilities and obligations. We are subject to stringent and complex federal, state and local environmental laws, regulations and permits, relating to, among other things, the generation, storage, handling, use, disposal, movement and remediation of natural gas, NGLs, crude oil and other hazardous materials; the emission and discharge of such materials to the ground, air and water; wildlife protection; and the health and safety of our employees. Failure to comply with these environmental requirements may result in our being subject to litigation, fines or other sanctions, including the revocation of permits and suspension of operations. We may incur significant costs and other compliance costs related to such requirements. We could be liable for any environmental contamination at our or our predecessors’ currently or formerly owned or operated properties or third party waste disposal sites, regardless of whether we were at fault. In addition to potentially significant investigation and remediation costs, such matters can give rise to claims from govern- mental 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, environ- mental 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. 21 In addition, various federal and state initiatives are underway to regulate, or further investigate the environ- mental 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: (cid:129) perform ongoing assessments of pipeline integrity; (cid:129) identify and characterize applicable threats to pipeline segments that could impact a high consequence area; (cid:129) maintain processes for data collection, integration and analysis; (cid:129) repair and remediate pipelines as necessary; and (cid:129) 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 dis- tributions 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. 22 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: (cid:129) damage to pipelines and plants, related equipment and surrounding properties caused by natural disasters and acts of terrorism; (cid:129) inadvertent damage from construction, farm and utility equipment; (cid:129) leaks or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities; (cid:129) fires and explosions; and (cid:129) 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: (cid:129) incur additional debt or guarantee other indebtedness; (cid:129) make distributions on, redeem or repurchase units; (cid:129) make certain investments and acquisitions; (cid:129) incur or permit certain liens to exist; (cid:129) enter into certain types of transactions with affiliates; (cid:129) merge, consolidate or amalgamate with another company; and (cid:129) 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 23 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-pay- ment 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 busi- ness 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 24 conflicts of interest, our General Partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. Crestwood is not limited in its ability to compete with us and is not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders. Crestwood is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, in the future, Crestwood may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while Crestwood may offer us the opportunity to buy additional assets from it, it is under no contractual obligation to do so and we are unable to predict whether or when such acquisitions might be completed. Cost reimbursements due to Crestwood and our General Partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our General Partner. Prior to making distributions on our common units, we will reimburse our General Partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by Crestwood and our General Partner in managing and operating us. Our partnership agreement provides that our General Partner will determine in good faith the expenses that are allocable to us. The reimbursements to Crestwood and our General Partner will reduce the amount of cash otherwise available for distribution to our unitholders. If you are not an eligible holder, you may not receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption. We have adopted certain requirements regarding those investors who may own our common units. Eligible holders are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the 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 25 increase the risk that we will be unable to maintain or increase our per-unit distribution level. There are no limitations in our Partnership Agreement or in 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 26 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: (cid:129) our existing unitholders’ proportionate ownership interest in us will decrease; (cid:129) the amount of cash available for distribution on each unit may decrease; (cid:129) the ratio of taxable income to distributions may increase; (cid:129) the relative voting strength of each previously outstanding unit may be diminished; and (cid:129) 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. 27 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: (cid:129) we were conducting business in a state but had not complied with the applicable limited partnership statute; or (cid:129) 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 part- nerships; 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: (cid:129) 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; 28 (cid:129) the continued accuracy of the representations and warranties contained in the Frontier Purchase and Sale Agreement; (cid:129) the performance by each party of its obligations under the Frontier Purchase and Sale Agreement; and (cid:129) 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 realiz- ing 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: (cid:129) unexpected operational events; (cid:129) adverse weather conditions; (cid:129) regulatory hurdles; (cid:129) facility or equipment malfunctions or breakdowns; (cid:129) a shortage of skilled labor; and (cid:129) risks associated with subcontractors’ services, supplies, cost escalation and personnel. 29 Financing the Frontier Acquisition will substantially increase our leverage. We may not be able to obtain debt financing for the acquisition on expected or acceptable terms. We intend to finance the Frontier Acquisition and related fees and expenses with the proceeds of the issuance of equity and debt, including the private placement of Class C Units, and, to the extent necessary or desirable, with borrowing under our revolving credit facility, borrowings under the Bridge Loans, the issuance of senior unsecured notes and/or cash on hand. After completion of the Frontier Acquisition, we expect our total outstanding indebtedness will increase from approximately $284 million as of December 31, 2010 to at least $469 million. The increase in our indebtedness may reduce our flexibility to respond to changing business and economic conditions or to fund capital expenditures or working capital needs. We intend to raise long term debt in advance of closing of the Frontier Acquisition. The assumptions underlying our estimate that the Frontier Acquisition will be accretive to our distributable cash flow per Common Unit includes assumptions about the interest rate we will be able to obtain in connection with such long term debt. We may not be able to obtain debt financing for the acquisition on expected or acceptable terms. The acquisition of the Frontier Assets could expose us to additional unknown and contingent liabilities. The acquisition of the Frontier Assets could expose us to additional unknown and contingent liabilities. We have performed a certain level of due diligence in connection with the acquisition of the Frontier Assets and have attempted to verify the representations made by Frontier, but there may be unknown and contingent liabilities related to the Frontier Assets of which we are unaware. Frontier has not agreed to indemnify us for losses or claims relating to the operation of the business or otherwise except to the limited extent described above. There is a risk that we could ultimately be liable for unknown obligations relating to the Frontier Assets for which indemnification is not available, which could materially adversely affect our business, results of operations, financial condition, and ability to make cash distributions. Tax Risks to Common Unitholders Our tax treatment depends on our being treated as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation or if we become subject to a material amount of additional entity-level taxation for state tax purposes, then it would substantially reduce the amount of cash available for distribution to our unitholders. The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. As long as we qualify to be treated as a partnership for federal income tax purposes, in general we will not be subject to federal income tax. Although a publicly-traded limited partnership is generally treated as a corporation for federal income tax purposes, a publicly-traded partnership such as us can qualify to be treated as a partnership for federal income tax purposes under current law so long as for each taxable year at least 90% of its gross income is derived from specified investments and activities. We believe that we qualify to be treated as partnership for federal income tax purposes because we believe that at least 90% of our gross income for each taxable year has been and is derived from such specified investments and activities. Although we intend to meet this gross income requirement, we may not find it possible, regardless of our efforts, to meet this gross income requirement or may inadvertently fail to meet this gross income requirement. If we do not meet this gross income requirement for any taxable year and the Internal Revenue Service, or IRS, does not determine that such failure was inadvertent, we would be treated as a corporation for such taxable year and each taxable year thereafter. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35 percent. Distributions would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through. If we were treated as a corporation at the state level, we would likely also be subject to entity-level state income tax at varying rates. Moreover, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms 30 of taxation. We are for example, subject to an entity-level tax in Texas. The imposition of any entity-level taxation, including a federal income tax imposed on us as a corporation or any entity-level state taxes, will reduce the amount of cash we can distribute each quarter to the holders of our common units. Therefore, our treatment as a corporation for federal income tax purposes or becoming subject to a material amount of additional state taxes could result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units. The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a ret- roactive 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 31 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 com- mon 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 deduc- tion 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. 32 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. 33 Item 3. Legal Proceedings We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business and disputes normally incident to our business. At December 31, 2010, we are not subject to any material lawsuits or other legal proceedings. Item 4. Reserved 34 Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of PART II 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. Quarter Ended High Low March 31, 2009. . . . . . . . . . . . . . . . . . . . June 30, 2009 . . . . . . . . . . . . . . . . . . . . . September 30, 2009 . . . . . . . . . . . . . . . . December 31, 2009 . . . . . . . . . . . . . . . . . March 31, 2010. . . . . . . . . . . . . . . . . . . . June 30, 2010 . . . . . . . . . . . . . . . . . . . . . September 30, 2010 . . . . . . . . . . . . . . . . December 31, 2010 . . . . . . . . . . . . . . . . . $14.84 $14.78 $17.88 $22.77 $21.20 $22.19 $24.68 $28.65 $10.06 $11.46 $13.52 $17.20 $18.58 $16.41 $18.99 $24.46 Distributions Per Common Unit $0.37 $0.37 $0.39 $0.39(1) $0.39 $0.42 $0.42 $0.43(2) Record Date Payment Date May 5, 2009 May 15, 2009 Aug. 14, 2009 Aug. 4, 2009 Nov. 13, 2009 Nov. 3, 2009 Feb. 2, 2010 Feb. 12, 2010 May 4, 2010 May 14, 2010 Aug. 13, 2010 Aug. 3, 2010 Nov. 12, 2010 Nov. 2, 2010 Feb. 11, 2011 Feb. 1, 2011 (1) The fourth quarter 2009 distribution is reflected as 2010 activity, since distributions are recorded when paid. (2) The fourth quarter 2010 distribution will be reflected as 2011 activity, since distributions are recorded when paid. The last reported sale price of our common units on the NYSE on February 14, 2011, was $29.71. As of that date, we had eight unitholders of record, which does not include beneficial owners whose units are held by a clearing agency, such as a broker or bank. Cash Distribution Policy Our cash distribution policy reflects a basic judgment that our unitholders are best served by our distributing cash available after expenses and reserves rather than retaining it. We will strive to finance our maintenance capital expenditures through cash generated from operations and to distribute all of our available cash. Since we are not directly subject to federal income tax, we have more cash to distribute to unitholders than would be the case were we subject to such tax. Our Partnership Agreement requires that we distribute all of our available cash quarterly, except under certain types of circumstances. Our ability to make quarterly distributions is subject to certain restrictions, including restrictions under our debt agreements and Delaware law. 35 Performance Graph The following performance graph compares the cumulative total unitholder return on our common units with the Standard & 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 $160 $120 $80 $40 8/7/07 12/31/07 12/31/08 12/31/09 12/31/10 Crestwood Midstream Partners LP Alerian MLP Index S&P 500 Index 36 Item 6. Selected Financial Data The information in this section should be read in conjunction with Items 7 and 8 of this annual report. In January 2010 we closed the Alliance Acquisition, which was comprised of the Alliance Midstream Assets originally acquired by Quicksilver in August 2008. Due to 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. 2010 Year Ended December 31, 2008 (In thousands, except per unit and volume data) 2009 2007 2006 Operating Results Data: Total revenues . . . . . . . . . . . . . . . . . . . . $ 113,590 65,718 Total operating expenses . . . . . . . . . . . . . 47,872 Operating income . . . . . . . . . . . . . . . . . . 34,322 Income before income taxes . . . . . . . . . . 34,872 Net income from continuing operations . . Loss from discontinued operations. . . . . . — Net income . . . . . . . . . . . . . . . . . . . . . . . 34,872 Diluted earnings per unit: From continuing operations per unit . . . . $ Net earnings per unit . . . . . . . . . . . . . . . $ Cash distributions per unit(1) . . . . . . . . . $ Net cash provided by (used in): $ 95,881 52,473 43,408 34,890 34,491 (1,992) 32,499 $ 76,084 $ 35,695 $ 13,918 11,340 2,578 2,591 2,456 (35) 2,421 22,513 13,182 9,161 8,848 (592) 8,256 38,933 37,151 28,725 28,472 (2,330) 26,142 1.03 $ 1.03 $ 1.66 $ 1.25 $ 1.18 $ 1.52 $ 1.03 $ 0.95 $ 1.39 $ 0.22 0.20 0.47 n/a n/a n/a Operating activities . . . . . . . . . . . . . . . $ 48,003 (149,345) Investing activities. . . . . . . . . . . . . . . . 100,598 Financing activities . . . . . . . . . . . . . . . 125,317 Volumes gathered (MMcf). . . . . . . . . . . . Volumes processed (MMcf) . . . . . . . . . . . 46,660 Adjusted gross margin (2)(4) . . . . . . . . . . $ 70,231 70,231 EBITDA (3)(4) . . . . . . . . . . . . . . . . . . . . $ 68,949 (54,818) (13,688) 93,955 54,386 $ 64,237 64,238 $ 52,572 $ 14,949 $ (148,079) 94,685 70,617 56,225 (73,797) 57,176 34,284 30,802 $ 50,282 $ 20,884 $ 50,293 21,120 6,445 (78,360) 74,712 14,263 13,496 5,506 5,519 Financial Condition Information: Property, plant and equipment, net. . . . . . $ 531,371 570,627 Total assets . . . . . . . . . . . . . . . . . . . . . . . 283,504 Long-term debt . . . . . . . . . . . . . . . . . . . . 9,877 Other long-term obligations(5) . . . . . . . . 258,753 Partners’ capital . . . . . . . . . . . . . . . . . . . $482,497 487,624 125,400 62,162 284,837 $ 441,863 $254,555 278,410 5,000 118,306 110,200 502,606 174,900 123,928 115,208 $128,456 134,623 — 503 118,652 (1) Reported amounts include the fourth quarter distribution on all common units paid in the first quarter of the subsequent year. (2) Defined as total revenues less operations and maintenance expense and general and administrative expense. Additional information regarding Adjusted Gross Margin, including a reconciliation of Adjusted Gross Margin to Net Income as determined in accordance with GAAP, is included in “Results of Operations” in Item 7 of this annual report. 37 (3) Defined as net income plus income tax provision, interest expense, and depreciation and accretion expense. Additional information regarding EBITDA, including a reconciliation of EBITDA to Net Income as determined in accordance with GAAP, is included in “Results of Operations” in Item 7 of this annual report. (4) For 2006, adjusted gross margin and EBITDA of $5.5 million less $3.1 million in depreciation and accretion expense equals reported net income of $2.4 million. (5) Other long-term obligations include the subordinated note payable to Crestwood, and Quicksilver prior to October 1, 2010, which was converted to common units in the fourth quarter of 2010, repurchase obligations to Quicksilver, which concluded in the forth quarter of 2009 and asset retirement obligations. 38 ITEM 7. 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: (cid:129) Current Year Highlights (cid:129) Overview and Performance Metrics (cid:129) Results of Operations (cid:129) Liquidity and Capital Resources (cid:129) 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. 39 In connection with the closing of the Crestwood Transaction, Quicksilver is providing us with transitional services on a temporary basis on customary terms. More than 100 experienced midstream employees who had previously been seconded to us from Quicksilver became employees of Crestwood. We also entered into an agreement with Quicksilver for the joint development of areas governed by certain of our existing commercial agreements and amended certain of our existing commercial agreements, most significantly to extend the terms of all Quicksilver gathering agreements to 2020 and to establish a fixed gathering rate of $0.55 Mcf at the Alliance System. Recent Events On February 18, 2011, we entered into a Purchase and Sale Agreement (the “Frontier Purchase and Sale Agreement”) with Frontier Gas Services, LLC, a Delaware limited liability company (“Frontier”), pursuant to which we agreed to acquire midstream assets (the “Frontier Assets”) in the Fayetteville Shale and the Granite Wash plays for a purchase price of approximately $338 million, with an additional $15 million to be paid to Frontier if certain operational objectives are met within six-months of the closing date (the “Frontier Acquisition”). The final purchase price is payable in cash, and we expect to finance the purchase through a combination of equity and debt as described below. Consummation of the Frontier Acquisition is subject to customary closing conditions and regulatory approval. There can be no assurance that these closing conditions will be satisfied. We expect to close the Frontier Acquisition in the second quarter of 2011. On February 18, 2011, we entered into a Class C Unit Purchase Agreement (the “Class C Unit Purchase Agreement”) with the purchasers named therein (the “Class C Unit Purchasers”) to sell approximately 6.2 million Class C Units in a private placement. The negotiated purchase price for the Class C Units is $24.50 per unit, resulting in gross proceeds to us of approximately $153 million. If the closing of the private placement is after the record date for our first quarter 2011 distribution in respect of our Common Units, the price per Class C Unit will be reduced by such distribution, but the total purchase price will remain $153 million, and the number of Class C Units issued will be increased accordingly. We intend to use the net proceeds from the private placement to fund a portion of the purchase price for the Frontier Acquisition. The private placement of the Class C Units pursuant to the Class C Unit Purchase Agreement is being made in reliance upon an exemption from the registration requirements of the Securities Act pursuant to Section 4(2) and Regulation D thereof. The closing of the private placement is subject to certain conditions including (i) the closing of the Frontier Acquisition, (ii) the receipt of, or binding commitments to fund the Frontier Acquisition through (A) equity proceeds of not less than $150 million pursuant to the Class C Unit Purchase Agreement, and (B) debt financing of not less than $185 million from the issuance or incurrence of (x) borrowings under our Credit Facility, (y) borrowings under a bridge facility, and/or (z) senior unsecured notes, senior subordinated notes and/or other debt securities, with the weighted average total effective yield for the aggregate of all debt in this item (ii)(B) to be no more than 8.75%, (iii) the adoption of an amendment to our Partnership Agreement to establish the terms of the Class C Units, (iv) NYSE approval for listing of the Common Units to be issued upon conversion of the Class C Units, and (v) our filing of this annual report with the SEC. In connection to the Class C Unit Purchase Agreement, we have agreed to enter into a registration rights agreement with the Class C Unit Purchasers (the “Registration Rights Agreement”). Pursuant to the Registration Rights Agreement, upon request of a Class C Unit holder, we will be required to file a resale registration statement to register (i) the Class C Units issued pursuant to the Class C Unit Purchase Agreement, (ii) the Common Units issuable upon conversion of the Class C Units issued, (iii) any Class C Units issued in respect of the Class C Units as a distribution in kind in lieu of cash distributions and (iv) any Class C Units issued as liquidated damages under the Registration Rights Agreement, as soon as practicable after such request. In connection with the proposed Frontier Acquisition, we obtained a commitment from UBS Loan Finance LLC, UBS Securities LLC, BNP Paribas, BNP Paribas Securities Corp., Royal Bank of Canada, RBC Capital Markets, RBS Securities Inc. and the Royal Bank of Scotland plc for senior unsecured bridge loans in an aggregate amount up to $200 million (the “Bridge Loans”). The commitment will expire upon the earliest to occur of (i) the termination of the Frontier Purchase and Sale Agreement in accordance with its own terms or (ii) 90 days after February 18, 2011. 40 The foregoing description of the Frontier Purchase and Sale Agreement and the Class C Unit Purchase Agreement is only a summary, does not purport to be complete and is qualified in its entirety by reference to the Frontier Purchase and Sale Agreement and Class C Unit Purchase Agreement, which are attached as Exhibit 2.3 and Exhibit 10.21, respectively to this annual report on Form 10-K and are included herein by reference. Overview and Performance Metrics We are a growth-oriented Delaware limited partnership engaged in gathering, processing, compression and treating of natural gas and delivery of NGLs produced from the Barnett Shale geologic formation of the Fort Worth Basin located in North Texas. We began operations in 2004 to provide midstream services primarily to Quicksilver as well as to other natural gas producers in this area. Additionally, all of our revenues are derived from operations in the Fort Worth Basin. During 2010, approximately 90% of our total gathering and processing volumes were comprised of natural gas owned or controlled by Quicksilver. Approximately 11% of our gathered volumes are comprised of natural gas purchased by Quicksilver from Eni SpA and gathered under 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: (cid:129) the level of successful drilling and production activity in areas where our systems are located; (cid:129) our ability to compete with other midstream companies for production volumes; and (cid:129) 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 41 alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA calculations may vary among entities, so our computation may not be comparable to EBITDA measures of other entities. In evaluating EBITDA, we believe that investors should also consider, among other things, the amount by which EBITDA exceeds interest costs, how EBITDA compares to principal payments on debt and how EBITDA compares to capital expenditures for each period. A reconciliation of EBITDA to amounts reported under GAAP is presented in “Results of Operations.” EBITDA is also used as a supplemental performance measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess: (cid:129) financial performance of our assets without regard to financing methods, capital structure or historical cost basis; (cid:129) 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 (cid:129) 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: Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operations and maintenance expense . . . . . . . . . . . . . . . . . . . . General and administrative expense . . . . . . . . . . . . . . . . . . . . . Adjusted gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and accretion expense . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income tax provision (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . Net income from continuing operations . . . . . . . . . . . . . . . . . . . . Loss from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . 2010 Year Ended December 31, 2008 2009 (In thousands, except volume data) $95,881 24,035 7,609 $113,590 28,392 14,967 $76,084 19,395 6,407 70,231 — 70,231 22,359 13,550 (550) 34,872 — 64,237 1 64,238 20,829 8,519 399 50,282 11 50,293 13,131 8,437 253 34,491 (1,992) 28,472 (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 . . . . . . . . . . . . . . . . Lake Arlington Dry System. . . . . . . . . Alliance Midstream Assets . . . . . . . . . 47,275 26,854 51,188 55,337 23,132 15,486 57,550 13,067 — 46,660 — — 54,386 — — 56,225 — — Total . . . . . . . . . . . . . . . . . . . . . . . . 125,317 93,955 70,617 46,660 54,386 56,225 42 The following table summarizes the changes in our revenues: Gathering Processing Other Total Revenue for the year ended ended December 31, 2008 . . . Volume changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Price changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revenue for the year ended ended December 31, 2009 . . . Volume changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Price changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $39,699 13,120 7,084 $59,903 19,994 3,497 (In thousands) $35,485 (1,161) 363 $34,687 (4,927) 436 $ 900 — 391 $ 1,291 — (1,291) $ 76,084 11,959 7,838 $ 95,881 15,067 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 43 2010, we re-borrowed $95 million to purchase the Alliance Midstream Assets and repaid $11 million upon the underwriters’ exercise of their over-allotment. The following table summarizes the details of interest expense for the year ended December 31, 2010 and 2009. Interest cost: Revolving credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repurchase obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subordinated note . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2010 2009 (In thousands) $11,532 $5,076 — 1,681 2,072 2,018 Total cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less interest capitalized. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,550 — 8,829 (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 44 in 2010, although the increased borrowing spreads as a result of our lenders’ redetermination will likely result in an increase to our interest expense: Year Ended December 31, 2009 2008 (In thousands) Interest cost: Revolving credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repurchase obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subordinated note . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $5,076 1,681 2,072 $ 3,158 4,283 2,802 Total cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less interest capitalized. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,829 (310) 10,243 (1,806) Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $8,519 $ 8,437 Liquidity and Capital Resources Our sources of liquidity include: (cid:129) cash generated from operations; (cid:129) borrowings under our Credit Facility; and (cid:129) 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: (cid:129) natural gas prices; (cid:129) dependency on Quicksilver and the Fort Worth Basin; and (cid:129) regulatory requirements. The volumes of natural gas that we gather and process are dependent upon the natural gas volumes produced by our customers, which may be affected by prevailing natural gas prices, their derivative programs, and the availability and cost of capital. We cannot predict future changes to natural gas prices or how any such pricing changes will influence producers’ behaviors. If reduced drilling and development programs in the Fort Worth Basin were to be sustained over a prolonged period of time, we could experience a reduction in volumes through our system and therefore reductions of revenue and cash flows. At this time, all of our revenue is derived from our operations in the Fort Worth Basin. In addition, approximately 90% of our total gathering and processing revenue is associated with natural gas volumes owned or controlled by Quicksilver. The risk of revenue fluctuations in the near-term is somewhat mitigated by the use of fixed fee contracts for providing gathering and processing and treating services to our customers, but we are still susceptible to volume fluctuations. To reduce the concentration risk associated with our dependency on one producer and one geographic area, we are regularly reviewing opportunities for both organic growth projects and acquisitions in other producing basins and with other producers. 45 We are subject to environmental laws, regulations and permits, including green house gas requirements that may expose us to significant costs or obligations. In general, these laws, regulations, and permits have become more stringent over time and are subject to further changes and could materially affect our financial condition and results of operations in the future. Significant Economic Factors That Impact our Business Changes in natural gas supply such as new discoveries of natural gas reserves, declining production in older fields and the introduction of new sources of natural gas supply, such as non-conventional and emerging natural gas shale plays, affect the demand from producers for our services. As these supply dynamics change, we anticipate that we will actively pursue projects that will allow us to provide midstream services to producers associated with the growth of new sources of supply. Changes in demographics, the amount of natural gas fired power generation, liquefied natural gas imports and shifts in industrial and residential usage affect the overall demand for natural gas. We believe that the key factors that impact our business are natural gas prices, our customers’ drilling and completion activities, and government regulation on natural gas pipelines. These key factors play an important role in how we evaluate our operations and implement our long-term strategies. Cash Flows 2010 Year Ended December 31, 2009 (In thousands) 2008 Net cash provided by operating activities . . . . . . . . . . . . . . . . Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . Net cash provided by (used in) financing activities . . . . . . . . . $ 48,003 (149,345) 100,598 $ 68,949 (54,818) (13,688) $ 52,572 (148,079) 94,685 2010 Cash Flows Compared to 2009 Cash Flows Provided by Operating Activities — The decrease in cash flows from operating activities resulted from an increase in the accounts receivable balance primarily related to the timing of collections from Quicksilver. Cash Flows Used in Investing Activities — The increase in cash flows used in investing activities resulted from the distribution to Quicksilver of $80.3 million related to the purchase of the Alliance Midstream Assets. Additionally, for the 2010 period, we spent $69.0 million for gathering assets and facilities, of which approximately $50 million relates to the expansion of the gathering system at Alliance. Cash Flows Provided by Financing Activities — Changes in cash flows provided by financing activities during the 2010 period resulted primarily from the net borrowings under our credit facilities of $158.1 million compared with the 2009 period pay down under our old credit facility of $49.5 million. This change is largely reflective of our funding of the purchase of the Alliance Midstream Assets for $84.4 million. We also borrowed $13.6 million to pay financing costs related to our new Credit Facility. In addition, we distributed $12.8 million more to our unitholders during the 2010 period due to increases in our quarterly distributions from December 31, 2009 to December 31, 2010. In January 2010, the underwriters of our equity offering exercised their option to purchase an additional 549,200 common units, which generated proceeds of $11.1 million compared to $80.8 million in 2009. 2009 Cash Flows Compared to 2008 Cash Flows Provided by Operating Activities — The increase in cash flows provided by operating activities resulted primarily from increased revenues and higher profitability associated with the natural gas gathered and processed through our systems, due to factors discussed above in our results of operations. Cash Flows Used in Investing Activities — The decrease in cash flows used in investing activities resulted from the lower capital expenditures used to expand our gathering system and processing capabilities, particularly due to an $80 million decrease in spending on plant capital, most significantly related to spending for the Corvette Plant construction. In 2009, we spent $26.9 million on gathering assets, and $27.9 million on processing facilities, which 46 included $26.6 million related to the Corvette Plant. The cash flows used in investing activities during 2009 include the payment of $25.8 million that was incurred and accrued at December 31, 2008. Cash Flows Used in Financing Activities — Changes in cash flows used in financing activities during 2009 consisted primarily of the 2009 net pay down under our old credit facility of $49.5 million compared with 2008 net borrowings of $169.9 million. In addition, we distributed $5.0 million more to our unitholders during 2009. Our secondary offering during December 2009, generated proceeds of $80.8 million for which there was no comparable 2008 event. Cash flows in 2009 also reflect $36.4 million of lower payments pursuant to repurchase obligations compared to 2008, when we purchased LADS. Capital Expenditures The midstream energy business is capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as either: (cid:129) expansion capital expenditures, which are made to construct additional assets, expand and upgrade existing systems, or acquire additional assets; or (cid:129) maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and extend their useful lives. Since our inception in 2004, we have made substantial capital expenditures. We anticipate that we will continue to make capital expenditures to develop our gathering and processing network as Quicksilver continues to expand its development efforts in the Fort Worth Basin. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives and to maintain our distribution levels. We have budgeted approximately $37 million in capital expenditures for 2011, of which $4 million is classified as maintenance capital expenditures. The capital budget includes approximately $33 million for the construction of pipelines and gathering systems, $3 million for compression assets and $1 million for processing plants. We expect to fund our capital expenditures through borrowing under our Credit Facility and from cash generated from operations. Repurchase Obligation to Quicksilver During 2009, our independent directors voted to acquire certain of the Cowtown Pipeline assets subject to the repurchase obligation that had an original cost of approximately $5.6 million. We paid $5.6 million for these assets in September 2009. Furthermore, our independent directors elected not to acquire certain Cowtown Pipeline assets that had been previously included in the repurchase obligation. In doing so, we derecognized assets with a carrying value of $56.8 million and also derecognized liabilities associated with the repurchase of $68.6 million. The difference of $11.8 million between the assets’ carrying values and their repurchase obligation was reflected as an increase in partners’ capital effective upon the decision not to purchase. We also entered into an agreement with Quicksilver to permit us to gather third party gas for a fee across the Cowtown Pipeline laterals retained by Quicksilver. The decision not to purchase certain Cowtown Pipeline assets did not have a material effect on our gathering and processing revenues as the natural gas stream from these laterals continues to flow into our Cowtown Pipeline gathering and processing facilities. We had been obligated to repurchase from Quicksilver a gas gathering system in Hill County, Texas, at its fair market value within two years after its completion and commencement of commercial service. As a result of this contractual purchase obligation, we have historically included the HCDS in our financial statements since our initial public offering. In November 2009, we and Quicksilver mutually agreed to waive both parties’ rights and obligations to transfer ownership of the HCDS to us. The revenues and expenses directly attributable to the HCDS for the periods prior to November 2009 have been retroactively reported as discontinued operations. For a complete description of our repurchase obligations to Quicksilver, see Note 2 to our consolidated financial statements included in Item 8 of this annual report. 47 Other Matters We regularly review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Since we strive to distribute most of our available cash to our unitholders, we will depend on a combination of borrowings under our Credit Facility, operating cash flows and debt or equity offerings to finance any future growth capital expenditures or acquisitions. Credit Facility and Subordinated Note For a complete description of Long Term Debt, see Note 7 to our consolidated financial statements included in Item 8 of this annual report. Total Contractual Obligations The following table summarizes our total contractual cash obligations as of December 31, 2010. Contractual Obligations Total 2011 2012 2013 2014 2015 Thereafter Payments Due by Period Long-term debt(1). . . . . . . . . . . . . . . . . . . . . . $283.5 42.3 Scheduled interest obligations(2) . . . . . . . . . . . 4.0 Contractual Obligations(3) . . . . . . . . . . . . . . . 9.9 Asset retirement obligations(4) . . . . . . . . . . . . (In millions) $ — $ — $ — $ — $283.5 6.7 8.9 0.4 0.7 — — 8.9 0.8 — 8.9 0.5 — 8.9 1.6 — Total contractual obligations . . . . . . . . . . . . $339.7 $10.5 $9.7 $9.6 $9.4 $290.6 $ — — — 9.9 $9.9 (1) As of December 31, 2010, we had $283.5 million outstanding under our Credit Facility. (2) Based on our debt outstanding and interest rates in effect at December 31, 2010, we would anticipate interest payments to be approximately $8.9 million annually on our Credit Facility. For each additional $10.0 million in borrowings, annual interest payments will increase by approximately $0.3 million. If the committed amount under our Credit Facility were to be fully utilized by year-end 2011 at interest rates in effect at December 31, 2010, we estimate that annual interest expenses would increase by approximately $3.7 million. If interest rates on our December 31, 2010 variable debt balance of $283.5 million increase or decrease by one percentage point, our annual income will decrease or increase by $2.8 million. (3) We lease office buildings and other property under operating leases. (4) For more information regarding our asset retirement obligations, see Note 8 to our consolidated financial statements, included in Item 8 of this annual report, none of which is expected to be due before 2015. Critical Accounting Estimates Management discusses with our Audit Committee the development, selection and disclosure of our critical accounting policies and estimates and the application of these policies and estimates. Our consolidated financial statements are prepared in accordance with GAAP in the United States. We believe our accounting policies are appropriately selected and applied. Use of Estimates GAAP requires management to make estimates and judgments that affect the amounts reported in the financial statements and notes. These estimates and judgments are based on information available at the time that we make such estimates and judgments. These estimates and judgments principally affected the reported amounts of depreciation expense, asset retirement obligations and stock-based compensation. 48 Depreciation Expense and Cost Capitalization Policies Policy Description Our assets consist primarily of natural gas gathering pipelines, processing plants and compression facilities. We capitalize all construction-related direct labor and material costs plus the interest cost associated with financing the construction of new facilities. These aggregate costs less the estimated salvage value are then depreciated using the straight-line method over the estimated useful life of the constructed asset. The costs of renewals and betterments that extend the useful life or substantially improve the efficiency of property, plant and equipment are also capitalized. The costs of repairs, replacements and normal maintenance projects are expensed as incurred. Judgments and Assumptions The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values which could impact current and future depreciation expense. When making expenditures, we also must determine whether they improve efficiency or extend the useful life of the underlying assets, to determine whether to capitalize such amounts paid. Asset Retirement Obligations Policy Description In certain instances, we have obligations to remove equipment and restore land at the end of our right-of-way period or the 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. 49 We do not believe there is a reasonable likelihood that there will be a material change in the future estimates or assumptions that we use to determine stock-based compensation expense. However, if actual results are not consistent with our estimates or assumptions, we may be exposed to changes in stock-based compensation expense that could be material. If actual results are not consistent with the assumptions used, the stock-based compensation expense reported in our financial statements may not be representative of the actual economic cost of the stock- based compensation. Off-Balance Sheet Arrangements We have no off-balance sheet arrangements within the meaning of Item 303(a)(4) of SEC Regulation S-K. Recently Issued Accounting Pronouncements The information regarding recent accounting pronouncements is included in Note 2 to our consolidated financial statements, included in Item 8 of this annual report. Item 7A. Quantitative and Qualitative Disclosures About Market Risk We have established policies and procedures for managing risk within our organization, including internal controls. The level of risk assumed by us is based on our objectives and capacity to manage risk. Credit Risk Our primary credit risk relates to our dependency on Quicksilver for the majority of our natural gas volumes, which causes us to be subject to the risk of nonpayment or late payment by Quicksilver for gathering and processing fees. 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. 50 Item 8. Financial Statements and Supplementary Data CRESTWOOD MIDSTREAM PARTNERS LP INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Income for the Years Ended December 31, 2010, 2009 and 2008 . . . . . . . . . Consolidated Balance Sheets as of December 31, 2010 and 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008 . . . . . . Consolidated Statements of Changes in Partners’ Capital for the Years ended December 31, 2010, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes to Consolidated Financial Statements for the Years Ended December 31, 2010, 2009 and 2008 . . . Page 52 53 54 55 56 57 51 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Partners of Crestwood Midstream Partners LP We have audited the accompanying consolidated balance sheets of Crestwood Midstream Partners LP (formerly Quicksilver Gas Services LP) and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of income, cash flows, and changes in partners’ capital for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the 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 Orga- nizations 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 52 CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF INCOME In thousands, except for per unit data Year Ended December 31, 2009 2010 2008 Revenue Gathering revenue — related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 77,645 5,749 Gathering revenue. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27,590 Processing revenue — related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,606 Processing revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Other revenue — related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $57,593 2,310 32,605 2,082 1,291 $34,468 5,231 30,127 5,358 900 Total revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113,590 95,881 76,084 Expenses Operations and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income from continuing operations before income taxes . . . . . . . . . . . . . . . Income tax provision (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28,392 14,967 22,359 65,718 47,872 — 13,550 34,322 (550) 34,872 — 24,035 7,609 20,829 52,473 43,408 1 8,519 34,890 399 19,395 6,407 13,131 38,933 37,151 11 8,437 28,725 253 34,491 (1,992) 28,472 (2,330) Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 34,872 $32,499 $26,142 General partner interest in net income . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,526 Common and subordinated unitholders’ interest in net income . . . . . . . . . $ 32,346 Basic earnings (loss) per unit: $ 1,172 $31,327 $ 647 $25,495 From continuing operations per common and subordinated unit . . . . . . $ From discontinued operations per common and subordinated unit . . . . . $ . . . . . . . . . . . . . . . . . $ Net earnings per common and subordinated unit Diluted earnings (loss) per unit: From continuing operations per common and subordinated unit . . . . . . $ From discontinued operations per common and subordinated unit . . . . . $ . . . . . . . . . . . . . . . . . $ Net earnings per common and subordinated unit Weighted average number of common and subordinated units outstanding: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distributions per unit (attributable to the period ended) . . . . . . . . . . . . . . $ 1.11 $ 1.38 — $ (0.08) 1.30 $ 1.11 1.03 $ 1.25 — $ (0.07) 1.18 $ 1.03 $ 1.17 $ (0.10) 1.07 $ $ 1.03 $ (0.08) 0.95 $ 29,070 31,316 1.66 24,057 28,189 1.52 $ 23,783 29,583 1.39 $ The accompanying notes are an integral part of these consolidated financial statements. 53 CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED BALANCE SHEETS In thousands, except for unit data December 31, 2010 December 31, 2009 Current assets ASSETS Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts receivable — related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2 1,679 23,003 1,052 25,736 531,371 13,520 $ 746 1,342 — 180 2,268 482,497 2,859 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $570,627 $487,624 LIABILITIES AND PARTNERS’ CAPITAL Current liabilities Current maturities of debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable — related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued additions to property, plant and equipment . . . . . . . . . . . . . . . . . . . . . Accounts payable and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subordinated note payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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) . . . . . . . . . . . . Subordinated unitholders (0 and 11,513,625 units issued and outstanding at December 31, 2010 and December 31, 2009, respectively) . . . . . . . . . . . . . . General partner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — 4,267 11,309 2,917 18,493 283,504 — 9,877 — $ 2,475 1,727 8,015 2,240 14,457 125,400 53,243 8,919 768 258,069 281,239 — 684 3,040 558 Total partners’ capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 258,753 284,837 $570,627 $487,624 The accompanying notes are an integral part of these consolidated financial statements. 54 CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS In thousands Year Ended December 31, 2009 2008 2010 Operating activities: Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 34,872 $ 32,499 $ 26,142 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion of asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non-cash interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes in assets and liabilities: Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prepaid expenses and other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts receivable — related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable — related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21,848 511 (768) 5,522 4,961 (270) (903) (23,003) 4,630 603 23,046 394 399 1,705 6,191 740 387 3,621 (33) Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48,003 68,949 14,545 184 196 1,017 9,787 (1,200) (612) 4,002 (1,489) 52,572 Investing activities: Capital expenditures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distributions to Quicksilver for Alliance Midstream Assets . . . . . . . . . . . . (69,069) (80,276) (54,818) — (148,079) — Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (149,345) (54,818) (148,079) Financing activities: Proceeds from revolving credit facility borrowings . . . . . . . . . . . . . . . . . . Debt issuance costs paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repayment of repurchase obligation to Quicksilver . . . . . . . . . . . . . . . . . . Repayments of credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repayment of subordinated note payable to Quicksilver . . . . . . . . . . . . . . . Proceeds from issuance of equity units . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity issuance cost paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contributions by Quicksilver . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distributions to unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Taxes paid for equity-based compensation vesting . . . . . . . . . . . . . . . . . . . 426,704 (13,568) — (268,600) — 11,088 (34) — (49,699) (5,293) 56,000 (1,446) (5,645) (105,500) — 80,760 (31) (816) (36,947) (63) 169,900 (486) (42,085) — (825) — — 111 (31,930) — Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . . . . . . . 100,598 (13,688) 94,685 Net cash increase (decrease) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents at beginning of period . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash paid for interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash paid for income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non-cash transactions: Working capital related to capital expenditures. . . . . . . . . . . . . . . . . . . . . . . . . Costs in connection with the equity offering . . . . . . . . . . . . . . . . . . . . . . . . . . Contribution of property, plant and equipment from Quicksilver. . . . . . . . . . . . . Disposition (acquisition) of property, plant and equipment under repurchase (744) 746 2 $ 443 303 746 (822) 1,125 $ 303 8,590 $ — $ 4,682 $ — $ 2,341 332 $ $ $ $ 11,309 — — $ 10,105 (416) 72,342 $ 31,920 — 9,668 obligation, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 111,070 (77,108) Equity contribution related to assets not purchased pursuant to repurchase obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repayment of subordinated note. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 57,736 — $ 20,663 $ — $ — — The accompanying notes are an integral part of these consolidated financial statements. 55 CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL In thousands Partners’ Capital Limited Partners Common Subordinated General Partner Total Balance at December 31, 2007 . . . . . . . . . . . . . . . . . $109,830 1,017 Equity-based compensation expense recognized . . . . . (16,135) Distributions paid to partners . . . . . . . . . . . . . . . . . . . 9,779 Contribution by Quicksilver . . . . . . . . . . . . . . . . . . . . 13,050 Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance at December 31, 2008 . . . . . . . . . . . . . . . . . 117,541 Equity-based compensation expense recognized . . . . . Distributions paid to partners . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contribution by Quicksilver . . . . . . . . . . . . . . . . . . . . Public offering of units, net of offering costs . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,705 (18,471) 18,384 81,830 80,313 (63) $ 356 — (15,140) — 12,456 (2,328) — (17,270) 12,926 9,712 — — $ 14 — (655) — 636 (5) — (1,206) 1,189 580 — — $110,200 1,017 (31,930) 9,779 26,142 115,208 1,705 (36,947) 32,499 92,122 80,313 (63) Balance at December 31, 2009 . . . . . . . . . . . . . . . . . 281,239 3,040 558 284,837 Equity-based compensation expense recognized . . . . . Distributions paid to partners . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distribution to Quicksilver. . . . . . . . . . . . . . . . . . . . . Public offering of units, net of offering costs . . . . . . . Conversion of subordinated note payable . . . . . . . . . . Conversion of subordinated units . . . . . . . . . . . . . . . . Taxes paid for equity-based compensation vesting . . . 5,522 (28,648) 22,614 (80,276) 11,054 57,736 (5,879) (5,293) — (18,651) 9,732 — — — 5,879 — — (2,400) 2,526 — — — — — 5,522 (49,699) 34,872 (80,276) 11,054 57,736 — (5,293) Balance at December 31, 2010 . . . . . . . . . . . . . . . . . $258,069 $ — $ 684 $258,753 The accompanying notes are an integral part of these consolidated financial statements. 56 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND DESCRIPTION OF BUSINESS Organization — Crestwood Midstream Partners LP (“CMLP”) is a Delaware limited partnership formed for the purpose of completing a public offering of common units and concurrently acquiring and operating midstream assets. As of September 30, 2010 our General Partner was owned by Quicksilver. On October 1, 2010, the Crestwood Transaction closed and Quicksilver sold all of its ownership interests in CMLP to Crestwood. The Crestwood Transaction includes 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: (cid:129) 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-con- trol provisions of our 2007 Equity Plan; (cid:129) acceleration of amounts due under our old $320 million credit facility, which was replaced with a new $400 million Credit Facility; (cid:129) termination of our omnibus agreement with Quicksilver, which was replaced with a new Omnibus Agreement; (cid:129) termination of our Services and Secondment Agreement with Quicksilver which we replaced, on a temporary basis, with a Transition Services Agreement with Quicksilver; (cid:129) extension of the tenor of all of our gathering and processing agreements with Quicksilver to 2020; and (cid:129) 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 mil- lion. 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: General partner interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Limited partner interest: Common unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 Ownership Percentage Crestwood Public Total 1.5% — 1.5% 61.7% 63.2% 36.8% 98.5% 36.8% 100.0% 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 Mid- stream 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: (cid:129) 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; (cid:129) 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 (cid:129) the Corvette Plant, placed in service during 2009, consisting of a 125 MMcfd natural gas processing unit that extracts NGLs from the natural gas stream and delivers customers’ residue gas and extracted NGLs to unaffiliated pipelines for sale downstream. Lake Arlington Dry System The LADS, located in eastern Tarrant County, consists of a gas gathering system and related gas compression facility with capacity of 230 MMcfd. This system gathers natural gas produced by our customers and delivers it to unaffiliated pipelines for sale downstream. Hill County Dry System As more fully described in Note 2, our financial information through November 2009 also included the operations of a gathering system in Hill County, Texas. The HCDS gathers natural gas and delivers it to unaffiliated pipelines for further transport and sale downstream. As of November 2009, the revenue and expenses directly attributable to the HCDS for the periods prior to November 2009 have been retrospectively reported as discontinued operations based upon the execution of the Repurchase Obligation Waiver. The HCDS had previously been subject to a repurchase obligation since its 2007 sale to Quicksilver. All repurchase obligations to Quicksilver were concluded by December 31, 2009. Notes 2 and 4 to our financial statements contain more information regarding the Repurchase Obligation Waiver. Alliance Midstream Assets During 2010, we completed the purchase of the Alliance Midstream Assets from Quicksilver for a purchase price of $84.4 million, which, with subsequent additions, we refer to as the Alliance System. The Alliance System consists of a gathering system and related compression facility with a capacity of 300 MMcfd, an amine treating facility with capacity of 360 MMcfd and a dehydration treating facility with capacity of 300 MMcfd. This system gathers natural gas produced by our customers and delivers it to unaffiliated pipelines for sale downstream. The 58 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) majority of the Alliance Midstream Assets operations commenced service in September 2009, although less significant operations had been conducted prior to that time. Because the purchase of the Alliance Midstream Assets was conducted among entities then under common control, GAAP requires the inclusion of the Alliance 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 Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 91,706 (47,610) As Previously Presented Alliance System (In thousands) $ 4,175 (4,863) Combined $ 95,881 (52,473) Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . $ 44,096 $ (688) $ 43,408 Basic earnings (loss) per limited partner unit: . . . . . . . . . Diluted earnings (loss) per limited partner unit: . . . . . . . . $ $ 1.33 1.21 $ (0.03) $ (0.03) $ $ 1.30 1.18 For the Year Ended December 31, 2008 As Previously Presented Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 76,084 (38,659) Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . $ 37,425 Basic earnings (loss) per limited partner unit: . . . . . . . . . Diluted earnings (loss) per limited partner unit: . . . . . . . . $ $ 1.08 0.96 Alliance System (In thousands) $ — (274) $ (274) $(0.01) $(0.01) Combined $ 76,084 (38,933) $ 37,151 $ $ 1.07 0.95 As of December 31, 2009 As Previously Presented Alliance System (In thousands) Combined Assets Property, plant and equipment, net . . . . . . . . . . . . . . . $396,952 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $396,952 $85,545 $85,545 $482,497 $482,497 Liabilities Accrued additions to property, plant and equipment . . . Asset retirement obligations . . . . . . . . . . . . . . . . . . . . Partners’ capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,011 7,654 204,561 Total liabilities and partners’ capital . . . . . . . . . . . . . . . . $216,226 $ 4,004 1,265 80,276 $85,545 $ 8,015 8,919 284,837 $301,771 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation — The accompanying consolidated financial statements and related notes present the financial position, results of operations, cash flows and changes in partners’ capital of our natural gas gathering and processing assets. The financial statements include historical cost-basis accounts of the assets of our Predecessor which were contributed to us by Quicksilver and two private investors in connection with the IPO. 59 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Our consolidated financial statements include the accounts of CMLP and its majority-owned subsidiaries. We eliminate all inter-company balances and transactions in preparing consolidated financial statements. Discontinued Operations — In November 2009, Quicksilver and our General Partner mutually agreed to waive both parties’ rights and obligations to transfer ownership of the HCDS from Quicksilver to us, which we refer to as the Repurchase Obligation Waiver. The Repurchase Obligation Waiver caused derecognition of the assets and liabilities directly attributable to the HCDS, most significantly the property, plant and equipment and repurchase obligation, beginning in November 2009. In addition, the Repurchase Obligation Waiver caused the elimination of the HCDS’ revenues and expenses from our consolidated results of operations beginning in November 2009. The revenues and expenses directly attributable to the HCDS for the periods prior to November 2009 have been retrospectively reported as discontinued operations. Use of Estimates — The preparation of the financial statements in accordance with GAAP requires manage- ment 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 depre- ciation. 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. Expen- ditures 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 cir- cumstances 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. 60 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Environmental Liabilities — Liabilities for environmental loss contingencies, including environmental reme- diation 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: (cid:129) persuasive evidence of an exchange arrangement exists; (cid:129) services have been rendered; (cid:129) the price for its services is fixed or determinable; and (cid:129) 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. 61 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 3. NET INCOME PER COMMON AND SUBORDINATED UNIT The following is a reconciliation of the weighted-average common and subordinated units used in the basic and diluted earnings per unit calculations for 2010, 2009 and 2008. The impact of the convertible debt is dilutive for 2009 and 2008. Years Ended December 31, 2009 2008 2010 Common and subordinated unitholders’ interest in net income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Common and subordinated unitholders’ interest in net loss from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $32,346 $33,286 $27,780 — (1,959) (2,285) Common and subordinated unitholders’ interest in net income . . . . . . . . . . . . Impact of interest on subordinated note . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $32,346 — $31,327 2,038 $25,495 2,748 Income available assuming conversion of convertible debt . . . . . . . . . . . . . . . $32,346 $33,365 $28,243 Weighted-average common and subordinated units — basic . . . . . . . . . . . . . . Effect of restricted phantom units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of subordinated note(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29,070 2,246 — Weighted-average common and subordinated units — diluted. . . . . . . . . . . . . 31,316 24,057 486 3,646 28,189 23,783 141 5,659 29,583 Basic earnings per unit: From continuing operations per common and subordinated unit . . . . . . . From discontinued operations per common and subordinated unit . . . . . . Net earnings per common and subordinated unit . . . . . . . . . . . . . . . . . . Diluted earnings per unit: From continuing operations per common and subordinated unit . . . . . . . From discontinued operations per common and subordinated unit . . . . . . Net earnings per common and subordinated unit . . . . . . . . . . . . . . . . . . Assumed conversion price(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 1.11 1.38 $ — $ (0.08) 1.30 $ 1.11 $ $ $ 1.03 1.25 $ — $ (0.07) 1.18 $ 1.03 $ — $ 15.28 $ $ 1.17 $ (0.10) 1.07 $ $ 1.03 $ (0.08) 0.95 $ 9.48 $ (1) Assumes that convertible debt is converted using the lesser of average closing price per unit or final closing price on December 31. See Note 7 for more information regarding the conversion of the subordinated note to Quicksilver. 4. DISCONTINUED OPERATIONS In November 2009, Quicksilver and our General Partner mutually agreed to waive both parties’ rights and obligations to transfer ownership of the HCDS from Quicksilver to us, which we refer to as the Repurchase Obligation Waiver. The Repurchase Obligation Waiver caused derecognition of the assets and liabilities directly attributable to the HCDS, most significantly the property, plant and equipment and repurchase obligation, beginning in November 2009. In addition, the Repurchase Obligation Waiver caused the elimination of the HCDS’ revenues and expenses from our consolidated results of operations beginning in November 2009. The revenues and expenses 62 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) directly attributable to the HCDS for the periods prior to November 2009 have been retrospectively reported as discontinued operations based upon our decision not to purchase the system from Quicksilver as follows: Years Ended December 31, 2009 2008 (In thousands) Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,771 (3,718) Operating Expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,045) Interest Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,974 (2,564) (1,740) Loss from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $(1,992) $(2,330) 5. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment consist of the following: Depreciable Life 2010 2009 December 31, Gathering systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Processing plants and compression facilities. . . . . . . . . . . . Construction in progress — gathering . . . . . . . . . . . . . . . . Rights-of-way and easements . . . . . . . . . . . . . . . . . . . . . . Land. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Buildings and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 years 20-25 years 20 years 20-40 years Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . Net property, plant and equipment . . . . . . . . . . . . . . . . . . . 6. ACCOUNTS PAYABLE AND OTHER Accounts payable and other consists of the following: (In thousands) $158,975 365,208 26,385 32,054 4,251 3,494 $145,457 332,053 5,630 29,522 4,251 2,732 590,367 (58,996) 519,645 (37,148) $531,371 $482,497 December 31, 2010 2009 (In thousands) Accrued operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 758 — Equity compensation payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Equity offering expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tax services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 280 Tax payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176 Legal services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 802 Consulting services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 726 Interest payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 175 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 204 242 416 236 — 376 — 660 106 $2,917 $2,240 63 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, 2010 December 31, 2009 (In thousands) Credit Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subordinated Note . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $283,504 — Current maturities of debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 283,504 — $125,400 55,718 181,118 (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: (cid:129) 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 (cid:129) 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. 64 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 8. ASSET RETIREMENT OBLIGATIONS The following table provides a reconciliation of the changes in the asset retirement obligation: Adjusted asset retirement obligations at December 31, 2009 . . . . . . . . . . . . . . . . . Incremental liability incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2010 (In thousands) $8,919 447 511 Ending asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $9,877 As of December 31, 2010, no assets are legally restricted for use in settling asset retirement obligations. 9. COMMITMENTS AND CONTINGENT LIABILITIES Litigation — At December 31, 2010, we were not subject to any material lawsuits or other legal proceedings. Casualties or Other Risks — We maintain coverage in various insurance programs, which provide us with property damage and other coverages which are customary for the nature and scope of our operations. Management of our General Partner believes that we have adequate insurance coverage, although insurance will not cover every type of loss that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially and, in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, we may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant loss for which we were not adequately insured, the loss could have a material impact on our consolidated financial condition and results of operations and cash flows. In addition, the proceeds of any available insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts our revenues, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our financial obligations. Regulatory Compliance — In the ordinary course of our business, we are subject to various laws and regulations. In the opinion of management of our General Partner, compliance with current laws and regulations will not have a material adverse effect on our financial condition or results of operations and cash flows. Environmental Compliance — Our operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. As an owner or operator of these facilities, we are subject to laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating our facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At December 31, 2010, we had recorded no liabilities for environmental matters. 65 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Commitments — The following table summarizes our commitment obligations: Pipeline Lease(1) Operating Lease(2) (In thousands) 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.8 — — — — — $0.8 $0.8 0.8 0.7 0.5 0.4 — $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. 66 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: Unvested phantom units — January 1, 2010 . . . . . . . Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Issued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cancelled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Payable in Cash Payable in Units Weighted Average Grant Date Fair Value $20.90 21.64 — — Units 33,240 (33,240) — — Weighted Average Grant Date Fair Value $12.75 15.29 23.38 24.44 Units 485,672 (695,582) 338,003 (6,567) 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. 67 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Prior to, or in connection with, our IPO, we entered into a number of agreements with Quicksilver. A description of those agreements follows: Contribution, Conveyance and Assumption Agreement — On August 10, 2007, we entered into a contribution, conveyance, and assumption agreement (“Contribution Agreement”) with our General Partner, certain other affiliates of Quicksilver and the private investors. The following transactions, among others, occurred just prior to the IPO pursuant to the Contribution Agreement: (cid:129) the transfer to us of all of the interests of certain entities; (cid:129) the issuance of the incentive distribution rights to our General Partner and the continuation of its 2% general partner interest in us; (cid:129) our issuance of 5,696,752 common units, 11,513,625 subordinated units and the right to receive $162.1 mil- lion, to Quicksilver in exchange for the contributed interests; and (cid:129) 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: (cid:129) restrictions on Quicksilver’s ability to engage in midstream activities in Quicksilver Counties; (cid:129) Quicksilver’s and our rights and obligations related to the LADS and the HCDS; (cid:129) our obligation to reimburse Quicksilver for all general and administrative expenses incurred by Quicksilver on our behalf; (cid:129) our obligation to reimburse Quicksilver for all insurance coverage expenses Quicksilver incurs or payments it makes with respect to our assets; and (cid:129) 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 Quick- silver in the principal amount of $50 million. Our new Credit Facility required us to terminate the Subordinated Note that had been payable to Quicksilver through the issuance of additional common units during the fourth quarter of 2010. For a more detailed description of the promissory note, see Note 7. With the purchase of the Alliance Midstream Assets, we also entered into an agreement with Quicksilver to lease pipeline assets attached to the Alliance System. We recognized $2.2 million of expense related to this agreement during 2010. Centralized cash management — Prior to our IPO, revenues settled with Quicksilver and other customers, net of expenses paid by Quicksilver on behalf of our Predecessor, are reflected as partners’ capital activity on the 68 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) consolidated balance sheets and as a reduction of net cash provided by financing activities on the consolidated statements of cash flows. Subsequent to the IPO, revenues settled and expenses paid on our behalf and are settled in cash on a monthly basis utilizing our bank accounts. Distributions — We paid distributions to Quicksilver of $30.3 million, $27.0 million and $23.3 million during 2010, 2009 and 2008, respectively. Allocation of costs — Prior to the closing of the Crestwood Transaction, the individuals supporting our operations were employees of Quicksilver. Our consolidated financial statements included costs allocated to us by Quicksilver for centralized general and administrative services performed by Quicksilver, as well as depreciation of assets utilized by 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 mil- lion, located in Tarrant and Denton Counties from Quicksilver. The acquired assets consist of gathering systems and a compression facility with a total capacity of 115 MMcfd, an amine treating facility with capacity of 180 MMcfd and a dehydration treating facility with capacity of 200 MMcfd. Under the terms of that agreement, Quicksilver agreed to allow us to gather all of the natural gas produced by wells that it operated and from future wells operated by it within the Alliance area through 2020. The gathering fee paid by Quicksilver is $0.55 per Mcf based on volumes. During 2010, we recognized $27.5 million related to this agreement. Hill County Dry System — In November 2009, Quicksilver and our General Partner mutually agreed to waive both parties’ rights and obligations to transfer ownership of the HCDS from Quicksilver to us, which we refer to as 69 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) the Repurchase Obligation Waiver. The Repurchase Obligation Waiver caused derecognition of the assets and liabilities directly attributable to the HCDS, most significantly the property, plant and equipment and repurchase obligation, beginning in November 2009. The difference of $8.9 million between the assets’ carrying values and the liabilities was reflected as an increase in partners’ capital effective upon the decision not to purchase. In addition, the Repurchase Obligation Waiver caused the elimination of the HCDS’ revenues and expenses from our consolidated results of operations beginning in November 2009. The revenues and expenses directly attributable to the HCDS for the period prior to November 2009 have been retrospectively reported as discontinued operations. We operate the HCDS pursuant to an operating agreement between Quicksilver and us effective as of the Crestwood Transaction. During 2010, we recognized $0.1 million related to this agreement. See Note 1 regarding amendments to gas gathering and processing contracts that were effective upon completion of the Crestwood Transaction. Crestwood Transaction — The Crestwood Transaction was funded by an equity contribution from funds managed by First Reserve and a $180 million senior secured Term B loan obtained by Crestwood Holdings payable to multiple financial investors. Crestwood Holdings’ ownership in us is pledged as collateral and is dependent on distributions from us to service the debt obligation which is not included in our financial position. Under the agreements governing the Crestwood Transaction, Quicksilver and Crestwood have agreed for two years not to solicit each 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: (cid:129) provide for the proper conduct of our business; (cid:129) comply with applicable law, any of our debt instruments or other agreements; or (cid:129) provide funds for distributions to partners for the succeeding four quarters. 70 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) The following table presents cash distributions for 2010 and 2009: Payment Date Pending Distributions February 11, 2011(2) . . . . . . . . . . Completed Distributions November 12, 2010(3) . . . . . . . . . August 13, 2010(4) . . . . . . . . . . . May 14, 2010(5) . . . . . . . . . . . . . February 12, 2010(5) . . . . . . . . . . November 13, 2009(6) . . . . . . . . . August 14, 2009(7) . . . . . . . . . . . May 15, 2009(7) . . . . . . . . . . . . . Attributable to The Quarter Ended Per Unit Distribution(1) Total Cash Distribution (In millions) December 31, 2010 $0.430 $14.3 September 30, 2010 June 30, 2010 March 31, 2010 December 31, 2009 September 30, 2009 June 30, 2009 March 31, 2009 $0.420 $0.420 $0.390 $0.390 $0.390 $0.370 $0.370 $13.9 $12.7 $11.6 $11.6 $ 9.7 $ 9.1 $ 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. 71 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Subordinated Units Termination. Under the terms of our partnership agreement and upon the payment of our quarterly cash distribution to unitholders on November 12, 2010, our subordination period ended. As a result, our 11,513,625 subordinated units held by Crestwood converted into common units on a one for one basis on November 15, 2010. The conversion of the subordinated units did not impact the amount of cash distributions paid. The conversion had no impact on our calculation of net income per limited partner unit since the subordinated units were previously included in our historical net income per limited partner unit calculation. Distributions of Available Cash to Unitholders. During the subordination period and assuming the absence of arrearages and the distributions of at least $0.30 distributed per unit per quarter: (cid:129) 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. (cid:129) 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 72 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) to register (i) the Class C Units issued pursuant to the Class C Unit Purchase Agreement, (ii) the Common Units issuable upon conversion of the Class C Units issued, (iii) any Class C Units issued in respect of the Class C Units as a distribution in kind in lieu of cash distributions and (iv) any Class C Units issued as liquidated damages under the Registration Rights Agreement, as soon as practicable after such request. In connection with the proposed Frontier Acquisition, we obtained a commitment from UBS Loan Finance LLC, UBS Securities LLC, BNP Paribas, BNP Paribas Securities Corp., Royal Bank of Canada, RBC Capital Markets, RBS Securities Inc. and the Royal Bank of Scotland plc for senior unsecured bridge loans in an aggregate amount up to $200 million (the “Bridge Loans”). The commitment will expire upon the earliest to occur of (i) the termination of the Frontier Purchase and Sale Agreement in accordance with its own terms or (ii) 90 days after February 18, 2011. 15. CONDENSED CONSOLIDATING FINANCIAL INFORMATION Condensed consolidating financial information for CMLP is presented below: For the Year Ended December 31, 2010 Crestwood Midstream Partners LP Restricted Guarantor Subsidiaries Eliminations (In thousands) Crestwood Midstream Partners LP Consolidated Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $113,590 47,936 17,782 $ — $113,590 65,718 — Operating income . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income from continuing operations before income tax . . . . Income tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income before equity in net earnings of subsidiaries . . Equity in net earnings of subsidiaries . . . . . . . . . . . . . . . . (17,782) 13,550 (31,332) — (31,332) 66,204 65,654 — 65,654 (550) 66,204 — — — — — — (66,204) 47,872 13,550 34,322 (550) 34,872 — Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 34,872 $ 66,204 $(66,204) $ 34,872 73 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) For the Year Ended December 31, 2009 Crestwood Midstream Partners LP Restricted Guarantor Subsidiaries Eliminations (In thousands) Crestwood Midstream Partners LP Consolidated — — — — — — — — — — — — — — — — $95,881 52,473 43,408 1 8,519 34,890 399 34,491 (1,992) 32,499 — $76,084 38,933 37,151 11 8,437 28,725 253 28,472 (2,330) 26,142 — Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $95,881 42,837 9,636 $ Operating income . . . . . . . . . . . . . . . . . . . . . . . . . Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income from continuing operations before income tax . . . . Income tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income from continuing operations . . . . . . . . . . . . . . . Income (loss) from discontinued operations . . . . . . . . . . . . Net income before equity in net earnings of subsidiaries . . Equity in net earnings of subsidiaries . . . . . . . . . . . . . . . . (9,636) 1 6,838 (16,473) — (16,473) (1,992) (18,465) 50,964 53,044 — 1,681 51,363 399 50,964 — 50,964 — (50,964) Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 32,499 $50,964 $(50,964) $32,499 For the Year Ended December 31, 2008 Crestwood Midstream Partners LP Restricted Guarantor Subsidiaries Eliminations (In thousands) Crestwood Midstream Partners LP Consolidated Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $76,084 31,992 6,941 $ Operating income . . . . . . . . . . . . . . . . . . . . . . . . . Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income from continuing operations before income tax . . . . Income tax provision . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income from continuing operations . . . . . . . . . . . . . . . Income (loss) from discontinued operations . . . . . . . . . . . . Net income before equity in net earnings of subsidiaries . . Equity in net earnings of subsidiaries . . . . . . . . . . . . . . . . (6,941) 11 4,153 (11,083) — (11,083) (2,330) (13,413) 39,555 44,092 — 4,284 39,808 253 39,555 — 39,555 — (39,555) Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 26,142 $39,555 $(39,555) $26,142 74 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Condensed Consolidated Balance Sheet December 31, 2010 Crestwood Midstream Partners LP Restricted Guarantor Subsidiaries Eliminations (In thousands) Crestwood Midstream Partners LP Consolidated ASSETS Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Properties, plant and equipment — net . . . . . . . . . . . . . Investment in subsidiaries . . . . . . . . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $291,637 11,142 228,587 12,890 $ 23,843 520,229 — 630 $(289,744) — (228,587) — $ 25,736 531,371 — 13,520 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . $544,256 $544,702 $(518,331) $570,627 LIABILITIES AND PARTNERS’ CAPITAL Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Partners’ capital $ 1,999 283,504 258,753 $306,238 9,877 228,587 $(289,744) — (228,587) $ 18,493 293,381 258,753 Total liabilities and partners’ capital . . . . . . . . . $544,256 $544,702 $(518,331) $570,627 December 31, 2009 Crestwood Midstream Partners LP Restricted Guarantor Subsidiaries Eliminations (In thousands) Crestwood Midstream Partners LP Consolidated ASSETS Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Properties, plant and equipment — net . . . . . . . . . . . . . Investment in subsidiaries . . . . . . . . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $173,307 — 292,439 2,194 $ 1,521 482,497 — 665 $(172,560) — (292,439) — $ 2,268 482,497 — 2,859 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . $467,940 $484,683 $(464,999) $487,624 LIABILITIES AND PARTNERS’ CAPITAL Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Partners’ capital $ 4,461 178,642 284,837 $182,556 9,688 292,439 $(172,560) — (292,439) $ 14,457 188,330 284,837 Total liabilities and partners’ capital . . . . . . . . . $467,940 $484,683 $(464,999) $487,624 75 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Condensed Consolidated Statement of Cash Flows For the Year Ended December 31, 2010 Crestwood Midstream Partners LP Restricted Guarantor Subsidiaries Eliminations (In thousands) Crestwood Midstream Partners LP Consolidated Net cash (used in) provided by operating activities. . . . . . . . . . . . . $ (23,588) $ 71,591 (57,990) — (80,276) Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Distributions to Quicksilver for Alliance Midstream Assets . . . (11,079) $ — — — $ 48,003 (69,069) (80,276) Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . (11,079) (138,266) Proceeds from revolving credit facility borrowings . . . . . . . . . Repayments of credit facility . . . . . . . . . . . . . . . . . . . . . . . . . Debt issuance costs paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from issuance of equity . . . . . . . . . . . . . . . . . . . . . . Equity issuance cost paid . . . . . . . . . . . . . . . . . . . . . . . . . . . Distributions to unitholders . . . . . . . . . . . . . . . . . . . . . . . . . . Taxes paid for equity-based compensation vesting . . . . . . . . . . Advances to Affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 426,704 (268,600) (13,568) 11,088 (34) (49,699) (5,293) 117,184 — — — — — — — (117,184) Net cash provided by financing activities . . . . . . . . . . . . . . . . . . . 217,782 (117,184) Net cash increase (decrease) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents at beginning of period. . . . . . . . . . . . . . 183,115 746 (183,859) — — — — — — — — — — — — — Cash and cash equivalents at end of period . . . . . . . . . . . . . . . . . . $ 183,861 $(183,859) $ — $ (149,345) 426,704 (268,600) (13,568) 11,088 (34) (49,699) (5,293) — 100,598 (744) 746 2 For the Year Ended December 31, 2009 Crestwood Midstream Partners LP Restricted Guarantor Subsidiaries Eliminations (In thousands) Crestwood Midstream Partners LP Consolidated Net cash (used in) provided by operating activities. . . . . . . Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . $ (10,972) $ 79,921 — (54,818) $ — — $ 68,949 (54,818) Net cash used in investing activities . . . . . . . . . . . . . . . . . — (54,818) Proceeds from revolving credit facility borrowings . . . Repayments of credit facility . . . . . . . . . . . . . . . . . . . Repayment of repurchase obligation to Quicksilver . . . Debt issuance costs paid . . . . . . . . . . . . . . . . . . . . . . Proceeds from issuance of equity . . . . . . . . . . . . . . . . Equity issuance cost paid . . . . . . . . . . . . . . . . . . . . . . Contributions by Quicksilver . . . . . . . . . . . . . . . . . . . Distributions to unitholders . . . . . . . . . . . . . . . . . . . . Taxes paid for equity-based compensation vesting. . . . Advances to Affiliates . . . . . . . . . . . . . . . . . . . . . . . . Net cash (used in) provided by financing activities. . . . . . . Net cash increase (decrease) . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents at beginning of period. . . . . . . . 56,000 (105,500) (5,645) (1,446) — (31) (816) (36,947) (63) 18,393 (76,055) (87,027) 303 — — — — 80,760 — — — — (18,393) 62,367 87,470 — — — — — — — — — — — — — — — Cash and cash equivalents at end of period . . . . . . . . . . . . $ (86,724) $ 87,470 $ — $ 76 (54,818) 56,000 (105,500) (5,645) (1,446) 80,760 (31) (816) (36,947) (63) — (13,688) 443 303 746 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) For the Year Ended December 31, 2008 Crestwood Midstream Partners LP Restricted Guarantor Subsidiaries Eliminations (In thousands) Net cash (used in) provided by operating activities. . . . . . . Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . $ (2,839) $ 55,411 — (148,079) $ — — Net cash used in investing activities . . . . . . . . . . . . . . . . . — (148,079) Proceeds from revolving credit facility borrowings . . . Repayment of subordinated note payable to parent . . . Repayment of repurchase obligation to Quicksilver . . . Debt issuance costs paid . . . . . . . . . . . . . . . . . . . . . . Contributions by Quicksilver . . . . . . . . . . . . . . . . . . . Distributions to unitholders . . . . . . . . . . . . . . . . . . . . Advances to Affiliates . . . . . . . . . . . . . . . . . . . . . . . . 169,900 (825) (42,085) (486) 111 (31,930) 139,099 — — — — — — (139,099) Net cash provided by financing activities . . . . . . . . . . . . . . 233,784 (139,099) Net cash increase (decrease) . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents at beginning of period. . . . . . . . 230,945 1,125 (231,767) — — — — — — — — — — — — Crestwood Midstream Partners LP Consolidated $ 52,572 (148,079) (148,079) 169,900 (825) (42,085) (486) 111 (31,930) — 94,685 (822) 1,125 Cash and cash equivalents at end of period . . . . . . . . . . . . $232,070 $(231,767) $ — $ 303 77 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) 16. SELECTED QUARTERLY DATA (UNAUDITED) The following presents a summary of selected quarterly data. Financial information has been revised to include the retroactive presentation of the Alliance Midstream Assets and revenues and expenses of the HCDS as discontinued operations for 2009. First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands) 2010 Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $24,739 $27,194 $30,366 $31,291 8,920 13,131 15,461 10,360 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,339 6,189 10,113 12,231 Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Basic earnings per limited partner unit: Net earnings per common and subordinated unit . . . . . . . . . . . . . . $ 0.20 $ 0.33 $ 0.40 $ 0.18 Diluted earnings per limited partner unit: Net earnings per common and subordinated unit . . . . . . . . . . . . . . $ 0.20 $ 0.31 $ 0.38 $ 0.18 2009 Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $23,964 $23,340 $23,236 $25,341 9,459 11,397 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,227 10,325 9,141 7,486 7,835 Net income from continuing operations. . . . . . . . . . . . . . . . . . . . . . . 10,029 (190) (348) (819) (635) Loss from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . 8,951 7,138 7,016 9,394 Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Basic earnings per limited partner unit: From continuing operations per common and subordinated unit . . . . $ 0.41 $ 0.32 $ 0.29 $ 0.36 From discontinued operations per common and subordinated unit . . $ (0.03) $ (0.03) $ (0.01) $ (0.01) 0.35 Net earnings per common and subordinated unit . . . . . . . . . . . . . . $ 0.38 $ 0.29 $ 0.28 $ Diluted earnings per limited partner unit: From continuing operations per common and subordinated unit . . . . $ 0.36 $ 0.29 $ 0.27 $ 0.33 From discontinued operations per common and subordinated unit . . $ (0.02) $ (0.03) $ (0.01) $ (0.01) 0.32 Net earnings per common and subordinated unit . . . . . . . . . . . . . . $ 0.34 $ 0.26 $ 0.26 $ Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures Disclosure Controls and Procedures Disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) are controls and other procedures that are designed to ensure that the information that we are required to disclose in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the management of our general partner, including the Chief Executive Officer and Chief Financial Officer of our General Partner, as appropriate to allow timely decisions regarding required disclosure. In connection with the preparation of this annual report, the management of our General Partner, under the supervision and with the participation of the Chief Executive Officer and the Chief Financial Officer of our General Partner, carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and 78 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) procedures as of December 31, 2010. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of December 31, 2010. Management’s Report on Internal Control Over Financial Reporting Management of our General Partner, under the supervision and with the participation of our General Partner’s Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) under the Exchange Act. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with existing policies or procedures may deteriorate. Under the supervision and with the participation of our General Partner’s Chief Executive Officer and Chief Financial Officer, our General Partner’s management conducted an assessment of our 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 (“COSO”). Based on this assessment, our General Partner’s management has concluded that, as of December 31, 2010, our internal control over financial reporting was effective. The effectiveness of our internal control over financial reporting as of December 31, 2010, has been audited by Deloitte & Touche LLP, our independent registered public accounting firm, and they have issued an attestation report expressing an unqualified opinion on the effectiveness of our internal control over financial reporting, as stated in their report included herein. Changes in Internal Control over Financial Reporting There were no changes in our internal control over financial reporting during the quarter ended December 31, 2010 that materially affected, or are reasonably likely to affect, our internal control over financial reporting. 79 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Partners of Crestwood Midstream Partners LP We have audited the internal control over financial reporting of Crestwood Midstream Partners LP (formerly Quicksilver Gas Services LP) and subsidiaries (the “Company”) as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our respon- sibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the Company maintained, in all material respects, effective 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. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2010 of the Company and our report dated February 25, 2011 expressed an unqualified opinion on those financial statements. /s/ DELOITTE & TOUCHE LLP Fort Worth, Texas February 25, 2011 Item 9B. Other Information None 80 PART III Item 10. Directors, Executive Officers and Corporate Governance General Our General Partner, Crestwood Gas Services GP LLC, manages our operations and activities. Unitholders are not entitled to elect our general partner or the directors of our general partner, or to participate, directly or indirectly, in our management or operations. The directors and executive officers of Crestwood Gas Services GP LLC oversee our operations. Crestwood Gas Services GP LLC currently has nine directors, three of whom are independent under the independence standards established by the NYSE. Directors and Executive Officers The following information is provided with respect to the directors and executive officers of Crestwood Gas Services GP LLC as of February 14, 2011. Name Age Position with Crestwood Gas Services GP LLC Robert G. Phillips . . . . . . . . . . . . . . . . 56 William G. Manias. . . . . . . . . . . . . . . . Terry M. Morrison . . . . . . . . . . . . . . . . Joel D. Moxley . . . . . . . . . . . . . . . . . . Kelly J. Jameson . . . . . . . . . . . . . . . . . 48 48 52 46 President, Chief Executive Officer and Chairman of the Board Senior Vice President — Chief Financial Officer Senior Vice President — Business Development Senior Vice President — Operations and Commercial Senior Vice President — General Counsel and Corporate Secretary Eric Guy . . . . . . . . . . . . . . . . . . . . . . . Mark G. Stockard . . . . . . . . . . . . . . . . Alvin Bledsoe . . . . . . . . . . . . . . . . . . . Thomas F. Darden . . . . . . . . . . . . . . . . Timothy H. Day. . . . . . . . . . . . . . . . . . Michael G. France . . . . . . . . . . . . . . . . Philip D. Gettig . . . . . . . . . . . . . . . . . . Joel C. Lambert . . . . . . . . . . . . . . . . . . J. Hardy Murchison . . . . . . . . . . . . . . . John W. Somerhalder II . . . . . . . . . . . . 40 Vice President and Controller 44 Vice President, Investor Relations and Treasurer 62 Director 57 Director 40 Director 33 Director 65 Director 42 Director 39 Director 55 Director Although the limited liability company agreement of our General Partner provides flexibility in the directors’ length of service, we anticipate that the sole member of our General Partner will appoint directors annually to serve until the earlier of their death, resignation, retirement, disqualification or removal. Officers serve at the discretion of the board of directors. The following biographies describe the business experience of the directors and executive officers of Crestwood Gas Services GP LLC. Also presented below is information regarding each director’s experience, qualifications, attributes and skills that led the sole member of Crestwood Gas Services GP LLC to the conclusion that each should serve as a director. Robert G. Phillips, was elected Chairman, President and Chief Executive Officer of our General Partner in October 2010 and has served on the Management Committee of Crestwood Holdings since May 2010. Since November 2007, he has served as Chairman, President and CEO of Crestwood Holdings Partners, LLC. Previously, Mr. Phillips served as President and Chief Executive Officer and a Director of Enterprise Products Partners L.P. from February 2005 until June 2007 and Chief Operating Officer and a Director of Enterprise Products Partners L.P. from September 2004 until February 2005. Mr. Phillips also served on the Board of Directors of Enterprise GP Holdings L.P., the general partner of Enterprise Products Partners L.P., from February 2006 until April 2007. He previously served as Chairman of the Board and CEO of GulfTerra Energy Partners, L.P., from 1999-2004, prior to 81 GTM’s merger with EPD, and held senior executive management positions with El Paso Corporation including President of El Paso Field Services from 1996-2004. Prior to that he was Chairman, President and CEO of Eastex Energy, Inc. from 1981-1995. Mr. Phillips currently serves as a Director of Pride International, Inc., one of the world’s largest offshore drilling contractors, and is a member of its audit committee. Mr. Phillips is also an Advisory Director of Triten Corporation, a leading international engineering firm and alloy products manufacturer. Mr. Phillips was selected to serve as the Chairman of the Board of Directors of our General Partner because he has experience in executive leadership for public companies in the energy industry and operational and financial expertise in the oil and gas business generally. William G. Manias, was appointed Senior Vice President and Chief Financial Officer of our General Partner in October 2010. Prior to joining our General Partner, Mr. Manias was Chief Financial Officer of Crestwood Holdings Partners, LLC from October 2009. From January 2006 through January 2009, Mr. Manias was the Chief Financial Officer of TEPPCO Partners, LP. Prior to TEPPCO, he served as Vice President of Business Development and Strategic Planning at Enterprise Product Partners, LP. From February 2004 to September 2004, he was Vice President and Chief Financial Officer of GulfTerra Energy Partners. Mr. Manias holds a Bachelor of Science in Civil Engineering from Princeton University, a Masters in Petroleum Engineering and a Masters of Business Administration from Rice University. Terry M. Morrison was appointed Senior Vice President Business Development of our General Partner in October 2010. From 2007 until joining our General Partner, Mr. Morrison was Senior Vice President of Crestwood Holdings Partners, LLC. From 1999 to 2007, he was Vice President of the Energy Marketing and Trading divisions of Florida Power & Light. From 1998 to 1999 Mr. Morrison was Vice President of Risk Management for Avista Energy. From 1990 to 1998, he was Vice President of Trading for El Paso Energy Marketing and its predecessor Eastex Energy Inc. Mr. Morrison holds a Bachelor of Science in Economics from the University of Houston. Joel D. Moxley was appointed Senior Vice President Operations and Commercial of our General Partner in October 2010. From April 2008 until joining our General Partner, Mr. Moxley was Senior Vice President of Crestwood Midstream Partners, LLC. From November 2005 to March 2008, he was Senior Vice President of Crosstex Energy, L.P. From September 2004 to November 2005, Mr. Moxley was a Senior Vice President for Enterprise Products Partners, LP. From January 2001 to August 2004 he was Vice President of El Paso Corporation. From 1997 to 2000 he was a Vice President for PG&E Corporation. Mr. Moxley holds a Bachelor of Science in Chemical Engineering from Rice University. Kelly J. Jameson, was appointed Senior Vice President, General Counsel & Corporate Secretary of our General Partner in October 2010. Prior to joining our General Partner, Mr. Jameson was employed by TransCanada Corporation from 2007 through October 2011, and was Senior Counsel and Corporate Secretary for the US subsidiaries of TransCanada Corporation. From 1996 to February 2007, he was employed by El Paso Corporation and was Senior Counsel and Assistant Corporate Secretary. Mr. Jameson has a B.B.A. from Southern Methodist University and a Juris Doctorate from Oklahoma City University. Eric Guy, was appointed Vice President and Controller of our General Partner in October 2010. Prior to joining our General Partner, Mr. Guy was Controller for Quicksilver Gas Services GP LLC and served in various financial roles with Quicksilver Resources Inc., an independent oil and gas company, since 2001. He began his career with KPMG LLP. Mr. Guy holds a B.B.A. from Baylor University and a Master of Business Administration from Texas Christian University. Mark G. Stockard was appointed Vice President, Investor Relations and Treasurer of our General Partner in October 2010. Prior to joining our General Partner, Mr. Stockard was Director of Financial Planning and Investor Relations at Buckeye Partners, LP from January 2010 to September 2010. From 2002 through October 2009 he was Treasurer of TEPPCO Partners, LP. Mr. Stockard holds a B.B.A. from Texas A&M University. Alvin Bledsoe was elected director of our General Partner in July 2007 and continues to serve as a director after the Crestwood Transaction. Prior to his retirement in 2005, Mr. Bledsoe served as a certified public accountant for 33 years at PricewaterhouseCoopers. From 1978 to 2005, he was a senior client engagement and audit partner for large, publicly-held energy, utility, pipeline, transportation and manufacturing companies. From 1998 to 2000, Mr. Bledsoe served as Global Leader of PwC’s Energy, Mining and Utilities Industries Assurance and Business 82 Advisory Services Group, and from 1992 to 2005 as a Managing Partner and Regional Managing Partner. During his career, Mr. Bledsoe also served as a member of PwC’s governing body. Mr. Bledsoe was selected to serve as a director of our General Partner due to his extensive background in public accounting and auditing, including experience advising publicly-traded energy companies. Thomas F. Darden served as President and Chief Executive Officer and director of our General Partner from January 2007 until October 1, 2010. Mr. Darden was re-elected to serve as a director of our General Partner effective October 1, 2010 pursuant to the Crestwood Transaction. Mr. Darden has also served on the Board of Directors of Quicksilver since December 1997 and became Chairman of its Board in March 1999. Prior to joining Quicksilver, Mr. Darden was employed by Mercury for 22 years in various executive level positions. Mr. Darden was selected to serve as a director of our General Partner due to his depth of knowledge of us, including our history, development, contracts and relationships, his 34 years of experience in the oil and gas industry and his positions as an executive of Quicksilver, our largest producer customer. Timothy H. Day was elected director of our General Partner in October 2010. Since 2000, Mr. Day served as a Managing Director of First Reserve Corporation, a private equity company which invests exclusively in the energy industry. Additionally, Mr. Day has served on the Management Committee of Crestwood Holdings since May 2010. Prior to joining First Reserve, Mr. Day worked with SCF Partners for three years and prior to that he worked for three years with CS First Boston and Salomon Brothers. Mr. Day previously served as a Director of Chart Industries, Inc. (Nasdaq: GTLS), (also serving on the Audit, Compensation and Nominating and Corporate Governance Committees), and Pacific Energy Partners (NYSE: PPX). Mr. Day holds a B.B.A. from the University of Texas and a Master of Business Administration from Harvard Business School. Mr. Day was elected to serve as a director of our General Partner due to his years of experience in financing energy related companies including significant energy investment experience at First Reserve and his general knowledge of midstream and downstream energy companies. Michael G. France was elected director of our General Partner in October 2010. Since 2007, Mr. France has served as a Director of First Reserve Corporation, a private equity company which invests exclusively in the energy industry. Additionally, Mr. France has served on the Management Committee of Crestwood Holdings since May 2010. From 2003 to 2007, Mr. France served as a Vice President in the Natural Resources Group, Investment Banking Division, at Lehman Brothers. From 1999 to 2001, he served as a Senior Consultant at Deloitte & Touche. Mr. France holds a B.B.A. (cum laude) in Finance from the University of Texas and a Master of Business Administration from Jones Graduate School of Management at Rice University. Mr. France was elected to serve as a director of our General Partner due to his years of experience in financing energy related companies including his energy investment experience at First Reserve and his general knowledge of upstream and midstream energy companies. Philip D. Gettig was elected director of our General Partner in July 2007 and continues to serve as a director after the Crestwood Transaction. From February 2000 to December 2005, Mr. Gettig served as the Vice President, General Counsel and Secretary of Prism Gas Systems I, L.P., a natural gas gathering and processing company that was purchased by Martin Midstream Partners L.P., a publicly-traded limited partnership, in November 2005. From 1981 to 1999, Mr. Gettig held various positions in the law department of Union Pacific Resources Company (UPR), a publicly traded exploration and production company with substantial natural gas gathering, processing and marketing operations. Positions held by Mr. Gettig included Managing Senior Counsel from 1996 to 1999. Mr. Gettig also served as General Counsel of Union Pacific Fuels, Inc., UPR’s wholly-owned gathering, processing and marketing affiliate, from 1996 to 1999. After his retirement from Prism in 2005, he has provided consulting and legal services to Prism and he has also provided such services to individuals and small businesses. Mr. Gettig was selected to serve as a director of our General Partner due to his 29 years of legal experience within the oil and gas industry. Joel C. Lambert was elected director of our General Partner in October 2010. Since 2007, Mr. Lambert has served as Associate General Counsel of First Reserve Corporation, a private equity company which invests exclusively in the energy industry. From 1998 to 2006, Mr. Lambert was an attorney in the Business and International Section of Vinson & Elkins LLP. In 1997 he was an Intern at the Texas Supreme Court, and has served as a Military Intelligence Specialist for the United States Army. Mr. Lambert holds a Bachelor of 83 Environmental Design (Magna Cum Laude) from Texas A&M University and a Juris Doctorate from the University of Texas School of Law. Mr. Lambert was elected to serve as a director of our General Partner due to his years of legal experience within the energy industry and his general knowledge of midstream energy companies. J. Hardy Murchison was elected as director of our General Partner in October 2010. Since 2001, Mr. Murchi- son has served as a Consultant for First Reserve Corporation, a private equity company which invests exclusively in the energy industry. Mr Murchison was a Managing Director of First Reserve from 2001 through January 2011. Prior to that, he was Vice President of Corporate Development at Range Resources Corporation, an independent oil and gas company. He began his career at Simmons & Company International. He serves as a Director of NFR Energy, L.L.C. and Cobalt International Energy, Inc. Mr. Murchison holds a B.A. from the University of Texas and a Master of Business Administration from Harvard Business School. Mr. Murchison was elected to serve as a director of our General Partner due to his years of experience in financing energy related companies including significant energy investment experience at First Reserve and his general knowledge of upstream energy companies. John W. Somerhalder II was elected director of our General Partner in July 2007 and continues to serve as a director after the Crestwood Transaction. Mr. Somerhalder has served as the President, Chief Executive Officer and a director of AGL Resources Inc., a publicly-traded energy services holding company whose principal business is the distribution of natural gas, since March 2006 and as Chairman of the Board of AGL Resources since November 2007. From 2000 to May 2005, Mr. Somerhalder served as the Executive Vice President of El Paso Corporation, a natural gas and related energy products provider and one of North America’s largest independent natural gas producers, where he continued service under a professional services agreement from May 2005 to March 2006. From 2001 to 2005, he served as the President of El Paso Pipeline Group. From 1996 to 1999, Mr. Somerhalder served as the President of Tennessee Gas Pipeline Company, an El Paso subsidiary company. From April 1996 to December 1996, Mr. Somerhalder served as the President of El Paso Energy Resources Company. From 1992 to 1996, he served as the Senior Vice President, Operations and Engineering, of El Paso Natural Gas Company. From 1990 to 1992, Mr. Somerhalder served as the Vice President, Engineering of El Paso Natural Gas Company. From 1977 to 1990, Mr. Somerhalder held various other positions at El Paso Corporation and its subsidiaries until being named an officer in 1990. Mr. Somerhalder was selected to serve as a director of our General Partner due to his years of experience in the oil and gas industry and his extensive business and management expertise, including as President, Chief Executive Officer and a director of a publicly-traded energy company. Committees of the Board of Directors The NYSE does not require its listed limited partnerships to have a compensation committee or a nominating and governance committee. Accordingly, each director of our General Partner may participate in the consideration of nomination and governance matters. Since the Crestwood Transaction, compensation matters relating to our executives and directors are reviewed and determined by the Management Committee of Crestwood Holdings (the “Management Committee”). Our General Partner’s board of directors has established an audit committee. The audit committee consists of Messrs. Bledsoe, Gettig and Somerhalder, with Mr. Bledsoe acting as the chairman of the audit committee. Our General Partner’s board of directors has determined that each of the members of the audit committee meets the independence and experience standards established by the NYSE and the Exchange Act and that Mr. Bledsoe is an “audit committee financial expert” within the meaning of SEC rules. The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our General Partner’s board of directors has also established a conflicts committee. The conflicts committee consists of Messrs. Bledsoe, Gettig and Somerhalder, with Mr. Gettig acting as the chairman of the conflicts committee, and is charged with reviewing specific matters that our General Partner’s board of directors believes may involve conflicts of interest. Any matters approved by the conflicts committee will be conclusively deemed to 84 be fair and reasonable to us, to have been approved by all of our unitholders, and not to involve a breach of any duties that may be owed to our unitholders. The charters of the audit committee and conflicts committee appear in the Company Overview section under Corporate Governance of our website www.crestwoodlp.com. Code of Business Conduct and Ethics Our General Partner’s board of directors has adopted a Code of Business Conduct and Ethics that applies to, among other persons, the principal executive officer, principal financial officer and principal accounting officer of our General Partner. A copy of this Code of Business Conduct and Ethics appears in the Company Overview section under Corporate Governance of our website www.crestwoodlp.com. We intend to post any amendments to or waivers of our Code of Business Conduct and Ethics with respect to the directors or executive officers of our General Partner in the Corporate Governance section of our website. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Exchange Act requires the executive officers and directors of our General Partner, and persons who own more than 10% of our common units, to file reports of ownership and changes in ownership with the SEC. The executive officers and directors of our general partner and owners of more than 10% of our common units are required by SEC rules to furnish us with copies of all Section 16(a) forms they file. Based solely on a review of the copies of such forms furnished to us and written representations from the directors and executive officers of our general partner, we believe that during 2010 all directors and executive officers of our General Partner and all owners of more than 10% of our common units were in compliance with all applicable Section 16(a) filing requirements, except that First Reserve GP and Philip W. Cook each filed a late report disclosing one transaction not timely reported. Item 11. Executive Compensation Compensation Discussion and Analysis Overview The following Compensation Discussion and Analysis is provided in two sections to cover the period of January 1, 2010 to October 1, 2010 (“Pre-Crestwood Transaction”) and the period from October 1, 2010 to December 31, 2010 (“Post-Crestwood Transaction”). Pre-Crestwood Transaction We do not directly employ any of the persons responsible for managing or operating our business. Instead, we were managed by our General Partner, the executive officers of which were also executive officers of Quicksilver and were compensated by Quicksilver in their capacities as such. The following table sets forth the name and title of the individuals who served during 2010 as the principal executive officer and principal financial officer of our General Partner and the three persons other than the principal executive officer and principal financial officer that constitute the most highly compensated executive officers of our General Partner in 2010 Pre-Crestwood Trans- action (collectively, the “Pre-Crestwood Transaction named executive officers”): Name Title Glenn Darden . . . . . . . . . . . . . . Chairman of the Board Thomas F. Darden . . . . . . . . . . . President and Chief Executive Officer Jeff Cook . . . . . . . . . . . . . . . . . Executive Vice President — Chief Operating Officer Philip W. Cook . . . . . . . . . . . . . Senior Vice President — Chief Financial Officer John C. Cirone . . . . . . . . . . . . . Senior Vice President, General Counsel and Secretary On August 10, 2007, we entered into the omnibus agreement with Quicksilver and Crestwood Gas Services GP LLC (the “old omnibus agreement”). Pursuant to the old omnibus agreement, Quicksilver provided certain general 85 and administrative services to us and we were obligated to reimburse Quicksilver for any expenses it incurred in conjunction with the performance of those services, including compensation and benefits provided by Quicksilver to the Pre-Crestwood Transaction named executive officers. Upon the closing of the Crestwood Transaction, the old omnibus agreement terminated except with respect to certain indemnification provisions which survive in accordance with their terms. Although we paid an allocated portion of Quicksilver’s direct costs of providing compensation and benefits to the Pre-Crestwood Transaction named executive officers, we had no direct control over such costs. Quicksilver’s board of directors and compensation committee established the base salary, bonus and other elements of com- pensation for Quicksilver’s executive officers, and such determinations were not subject to approvals by our General Partner’s board of directors or any of its committees. In addition to compensation paid to the Pre-Crestwood Transaction named executive officers by Quicksilver, the Pre-Crestwood Transaction named executive officers were eligible to participate in our 2007 Equity Plan, which is administered by our General Partner’s board of directors. Other than awards granted under this plan, the Pre- Crestwood Transaction named executive officers received no other compensation from us. Compensation Objectives, Strategies and Elements — Pre-Crestwood Transaction Pursuant to the old omnibus agreement, we were allocated a portion of the direct costs associated with the compensation and benefits provided by Quicksilver to the Pre-Crestwood Transaction named executive officers. In discussing the allocated portion of the costs for compensation and benefits to the Pre-Crestwood Transaction named executive officers for 2010, the Chief Executive Officer and Chief Financial Officer of Quicksilver (who served as the Chairman of the Board and the Chief Financial Officer, respectively, of our General Partner) determined that it was appropriate for us to bear a portion of these costs in two forms. The first component was an allocation to us of a percentage of costs for base salary and benefits provided by Quicksilver to the Pre-Crestwood Transaction named executive officers, generally based on the estimated amount of time that the Pre-Crestwood Transaction named executive officers devoted to our business and affairs relative to the amount of time they devoted to those of Quicksilver. For 2010, Quicksilver allocated $0.2 million of these costs to us. In determining this amount, Quicksilver considered the estimated amount of time that the Pre-Crestwood Transaction named executive officers devoted to our business and affairs, the amounts of the compensation and benefits provided by Quicksilver to them and the value of the equity-based awards our General Partner’s board of directors made to them in the form of phantom partnership equity. This amount was paid by us to Quicksilver and not to the Pre-Crestwood Transaction named executive officers directly. The second component was a grant of equity-based awards under the 2007 Equity Plan. For 2010, this grant made up 25% of the total long-term incentive equity-based awards payable to each Pre-Crestwood Transaction named executive officer. The other 75% was granted directly by Quicksilver. We agreed to award these long-term incentive equity-based awards because we did not bear any portion of the 2010 annual cash bonus paid to the Pre- Crestwood Transaction named executive officers, which was borne entirely by Quicksilver, and we believed that these grants aligned the interests of the Pre-Crestwood Transaction named executive officers directly with those of our unitholders. This was the only compensation the Pre-Crestwood Transaction named executive officers received from us in 2010. Although our General Partner’s board of directors had no direct control over the compensation paid to the Pre- Crestwood Transaction named executive officers by Quicksilver, our General Partner’s board of directors reviewed and concurred with Quicksilver’s compensation philosophy and strategies with respect to Quicksilver’s executive officers. These strategies for 2010 included the long-term incentive equity-based component mentioned above. Generally, Quicksilver targets long-term incentive compensation, in the form of equity-based awards, at the 50th to 75th percentile for Quicksilver’s peer group. In consultation with Hewitt Associates LLC, the compensation consultants employed by Quicksilver, Quicksilver’s management proposed to Quicksilver’s compensation com- mittee, and Quicksilver’s compensation committee concurred, that the long-term incentive compensation provided to Quicksilver’s executive officers in the form of equity-based awards would consist of three components in the following percentages (based on grant date values) for 2010: options to purchase Quicksilver common stock 86 (37.5%); restricted shares of Quicksilver common stock (37.5%); and awards in the form of phantom partnership equity (25%). Our General Partner’s board of directors determined that it would be desirable to grant equity-based awards to the Pre-Crestwood Transaction named executive officers in order to encourage them to think and act like owners of the partnership, to provide them additional incentives to advance our interests and the interests of holders of our units, and to enhance their commitment to our success. Our General Partner’s board of directors also believed these awards were appropriate, because they reduced the amount of cash we paid directly to Quicksilver for the services of the Pre-Crestwood Transaction named executive officers in 2010. For the Pre-Crestwood Transaction named executive officers other than the Chief Executive Officer, the amounts of awards were determined by our General Partner’s board of directors based on the recommendations of the Chief Executive Officer and his evaluation of the performance of each other named executive officer. In addition, our General Partner’s board of directors considered the appropriateness of the amounts awarded relative to the desired effect of the awards in motivating the Pre-Crestwood Transaction named executive officers to achieve the goals of the partnership. Our General Partner’s board of directors agreed that 25% of the grant date value of the total long-term incentive equity-based awards provided to the Pre-Crestwood Transaction named executive officers in 2010 should consist of phantom partnership equity. Our General Partner’s board of directors also considered and was satisfied with the appropriateness of the dollar values established by Quicksilver’s compensation committee for this purpose. Accordingly, our General Partner’s board of directors approved, effective January 4, 2010, the following grants of phantom units to the Pre-Crestwood Transaction named executive officers under the 2007 Equity Plan: Executive Number of Phantom Units Glenn Darden . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thomas F. Darden . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Jeff Cook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Philip W. Cook. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . John C. Cirone . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38,182 38,182 17,859 14,780 13,548 The phantom units vest one-third on the first business day occurring on or after each of the first three anniversaries of the date of grant (or, if earlier, the named executive officer’s death or disability or a change-in-con- trol) and are to be settled in common units immediately upon vesting. Our general partner’s board of directors determined that, in order to simplify administration of partner capital accounts, it was appropriate to grant phantom units that settle in common units near the end of the year. As a result of the Crestwood Transaction which closed on October 1, 2010, 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 equity-based compensation program resulting from the change-in-control of provisions of our amended 2007 Equity Plan. This affected all outstanding units and results in there being no unvested units outstanding immediately thereafter. Post-Crestwood Transaction We do not directly employ any of the persons responsible for managing or operating our business. Instead, we are managed by our General Partner, the executive officers of which are also executive officers of Crestwood and are compensated by Crestwood in their capacities as such. The following table sets forth the name and title of the individuals who served during 2010 Post-Crestwood Transaction as the principal executive officer and principal financial officer of our General Partner and the four persons other than the principal executive officer and principal 87 financial officer that constitute the most highly compensated executive officers of our General Partner in 2010 Post- Crestwood Transaction (collectively, the “Post-Crestwood Transaction named executive officers”): Name Title Robert G. Phillips . . . . . . . . . . . . . . President, Chief Executive Officer and Chairman of the Board William G. Manias . . . . . . . . . . . . . Senior Vice President — Chief Financial Officer Terry M. Morrison . . . . . . . . . . . . . Senior Vice President — Business Development Joel D. Moxley . . . . . . . . . . . . . . . . Senior Vice President — Operations and Commercial Eric Guy. . . . . . . . . . . . . . . . . . . . . Vice President — Controller Mark G. Stockard . . . . . . . . . . . . . . Vice President, Investor Relations and Treasurer Compensation Methodology On October 8, 2010, we entered into a new Omnibus Agreement with Crestwood and our General Partner (the “Omnibus Agreement”). Pursuant to the Omnibus Agreement, Crestwood provides certain general and admin- istrative services to us and we are obligated to reimburse Crestwood for any expenses it incurs in conjunction with the performance of those services, including compensation and benefits provided by Crestwood to the Post- Crestwood Transaction named executive officers. Although we pay an allocated portion of Crestwood’s direct costs of providing compensation and benefits to the Post-Crestwood Transaction named executive officers, we have no direct control over such costs. Crestwood’s Management Committee, comprised of Messrs. Day, France and Phillips, establishes the base salary, bonus and other elements of compensation for Crestwood’s executive officers, and such determinations are not subject to approvals by our General Partner’s board of directors or any of its committees. For the Post-Crestwood Transaction named executive officers other than the Chief Executive Officer, the compensation and amounts of awards are determined based on the recommendations of the Chief Executive Officer and his evaluation of the performance of each other Post-Crestwood Transaction named executive officer. Compensation and amounts of awards for the Chief Executive Officer are determined by the Management Committee with the abstention of Mr. Phillips. In addition to compensation paid to the Post-Crestwood Transaction named executive officers by Crestwood, certain of the Post-Crestwood Transaction named executive officers are eligible to participate in our 2007 Equity Plan, which is administered by our General Partner’s board of directors. In 2010, Messrs. Guy and Stockard were the only Post-Crestwood Transaction named executive officers granted awards under the 2007 Equity Plan. Certain Post-Crestwood Transaction named executive officers including Messrs. Phillips, Manias, Morrison and Moxley were issued incentive units in Crestwood in 2010. The incentive units represent a profits interest in Crestwood, and entitle the holders to share in distributions of Crestwood. Compensation Objectives As we do not directly compensate the executive officers of our General Partner, we do not have any set compensation programs. The elements of Crestwood’s compensation program as administered by the Management Committee and discussed below, along with Crestwood’s other rewards, are intended to provide a total rewards package designed to yield competitive total cash compensation, drive performance and reward contributions in support of the businesses of Crestwood and other Crestwood affiliates, including us, for which the Post-Crestwood Transaction named executive officers perform services. We are allocated a percentage of costs for base salary and benefits provided by Crestwood to the Post-Crestwood Transaction named executive officers, generally based on the estimated amount of time that the Post-Crestwood Transaction named executive officers devote to our business and affairs relative to the amount of time they devote to those of Crestwood. For 2010 Post-Crestwood Transaction, Crestwood allocated $1.0 million of these costs to us. In determining this amount, Crestwood considered the estimated amount of time that the Post-Crestwood Transaction named executive officers devoted to our business and affairs and the amounts of the compensation and benefits provided by Crestwood to them. Although we bear an allocated portion of Crestwood’s costs of providing compensation and benefits to the Post-Crestwood named executive officers, we do not have control over such costs and do not establish or direct the compensation policies or practices of Crestwood. Post-Crestwood Transaction, Crestwood paid to its employees certain incentive compen- sation based on the performance of Quicksilver pursuant to the Crestwood Transaction and as such did not set any 88 Crestwood specific performance-based criteria for 2010 and did not have any other specific performance-based objectives. For 2011 and future years, Crestwood and the Management Committee plan to set Crestwood specific performance based criteria and objectives for performance based compensation of its employees and certain Post- Crestwood Transaction named executive officers as applicable. Additionally, as required under the 2007 Equity Plan the board of directors of our General Partner shall participate in the determination of appropriate performance based criteria and goals for such plans. Elements of Compensation. Crestwood’s executive officer compensation package includes a combination of annual cash and long-term incentive compensation including awards under Crestwood’s employee benefit plans and incentive units from Crestwood. Elements of compensation which to the Post-Crestwood Transaction named executive officers may be eligible to receive from Crestwood consist of the following: (1) annual base salary; (2) discretionary annual cash awards; (3) awards pursuant to Crestwood’s employee benefit plans and (4) where appropriate, other compensation, including limited perquisites. Additionally, elements of long-term incentive compensation that certain Post-Crestwood Transaction named executive officers may be eligible to receive include incentive units from Crestwood, the cost of which is not allocated to Crestwood but play a key role in enabling our General Partner to attract, recruit, hire and retain qualified executive officers. Annual Base Salary. Base salary is intended to provide fixed compensation to the Post-Crestwood Trans- action named executive officers for their performance of core duties with respect to our General Partner, Crestwood and its affiliates, including us, and to compensate for experience levels, scope of responsibility and future potential. Base salaries are not intended to compensate individuals for extraordinary performance or for above average company performance. The base salaries of the Post-Crestwood Transaction named executive officers are reviewed on an annual basis, as well as at the time of promotion and other changes in responsibilities or market conditions. Discretionary Annual Cash Awards. In addition to the annual base salary, the Post-Crestwood Transaction named executive officers may be eligible to receive discretionary annual cash awards that, if awarded, are paid in a lump sum near the end of the fiscal year. These cash awards are designed to provide the Post-Crestwood Transaction named executive officers with competitive incentives to help drive performance and promote achievement of Crestwood’s and our business objectives. Employee Benefit Plan Awards. The Post-Crestwood Transaction named executive officers may be eligible to receive awards pursuant to our 2007 Equity Plan, which is administered by the Management Committee with the participation of our General Partner’s board of directors to establish appropriate performance based criteria and goals and Crestwood’s employee benefit plans. These employee benefit plan awards are designed to reward the performance of the Post-Crestwood Transaction named executive officers by providing annual inventive oppor- tunities tied to our annual performance and that of Crestwood. In particular, these awards are provided to certain of the Post-Crestwood Transaction named executive officers in order to provide competitive incentives to these executives who can significantly impact performance and promote achievement of our and Crestwood’s business objectives. Other Compensation. Crestwood generally does not pay for perquisites for any of the Post-Crestwood Transaction named executive officers. No perquisites are paid for services rendered to us. Crestwood provides a life insurance policy and long term disability policy for all of its employees including the Post-Crestwood Transaction named executive officers with the annual premiums being paid by Crestwood. Crestwood does not provide any greater allocation toward employee health insurance premiums than is provided for all other employees covered on the health benefits plan. Compensation Objectives, Strategies and Elements for 2011 Compensation for 2011 was determined using the same objectives, strategies and elements as were used for the period of October 1, 2010 through December 31, 2010 pursuant to Crestwood Transaction. 2007 Equity Plan Our 2007 Equity Plan is designed to promote our interests by providing to directors, officers and selected employees and consultants of our General Partner or its affiliates incentive compensation based on our common 89 units. Individuals that are selected to participate in the 2007 Equity Plan are determined by the equity committee or the board of directors of our General Partner, as applicable, to receive an award and are (i) officers or other employees of our General Partner who perform services for us, our General Partner or one of our or its affiliates, (ii) consultants who perform services for us, our General Partner or one of our or its affiliates or (iii) members of the board of directors of our General Partner who are not employees of our General Partner or one of its affiliates. The 2007 Equity Plan is administered by the board of our General Partner or a committee thereof. Any such committee will not administer phantom unit awards granted to non-employee directors of the board of our General Partner. The board has the full authority and discretion to administer the 2007 Equity Plan and to take any action that is necessary or advisable in connection with its administration. The 2007 Equity Plan authorizes the granting of options, restricted units, phantom units, unit appreciation rights, performance units and performance bonuses. The maximum number of our common units that may at any time be delivered or reserved for delivery under the 2007 Equity Plan is 750,000 common units. The total number of common units available under the 2007 Equity Plan will be adjusted to include units that relate to awards granted under the 2007 Equity Plan that (i) expire or are forfeited, (ii) are withheld or tendered in payment of the exercise price of an option or in satisfaction of the taxes required to be withheld in connection with any award granted under the 2007 Equity Plan or (iii) are subject to an appreciation right that are not transferred to a participant upon exercise of the appreciation right. The 2007 Equity Plan may be amended from time to time by the board of directors of our General Partner, but may not be amended without further approval of our unitholders if such amendment would result in the plan no longer satisfying any applicable requirements of the principal national securities exchange on which the common units are traded or Rule 16b-3 of the Exchange Act. No amendment of any outstanding option to reduce the exercise price will be authorized without the further approval of our unitholders. Furthermore, no option will be cancelled and replaced with options having a lower option price without further approval of our unitholders. Unless terminated earlier, the 2007 Equity Plan will terminate on July 24, 2017, after which no further awards may be made. The 2007 Equity Plan will continue to govern outstanding awards, and its termination will not adversely affect the terms of any outstanding award. Change-in-Control Arrangements In the event of a change-in-control as described in the 2007 Equity Plan, all of a named executive officer’s equity-based awards that have been granted under the 2007 Equity Plan would immediately vest. The board of directors of our General Partner believes that this change-in-control arrangement aligns the interests of the named executive officers with those of the holders of our units. Employment Agreements With the exception of Mr. Stockard, none of the Post-Crestwood named executive officers operate under employments agreements. Pursuant to a letter agreement dated September 7, 2010, between Mr. Stockard and Crestwood, Mr. Stockard became the Vice President, Investor Relations and Treasurer of our General Partner effective October 1, 2010. Pursuant to the terms of that agreement, Mr. Stockard will receive an annual base salary of $220,000. He will be eligible to receive an annual cash bonus of up to 50% of his base salary; as determined by the Management Committee based upon his individual performance and the performance of Crestwood and us based on meeting annual financial goals and non-financial goals set by the Management Committee or our General Partner’s board of directors. Mr. Stockard will be issued an annual equity grant in the form of phantom units under the 2007 Equity Plan in an amount equal to 45% of his base salary. Mr. Stockard received an initial one-time equity grant of 4,042 restricted units under the 2007 Equity Plan, with distribution rights. In addition, Mr. Stockard was issued 20,000 incentive units in Crestwood. Compensation Committee Report As our General Partner does not have a compensation committee, the Management Committee provides the oversight, administers and makes decisions regarding Crestwood’s compensation policies and plans with the 90 exception of the 2007 Equity Plan which provides for the participation of our General Partner’s board of directors to establish appropriate performance based criteria and goals. Additionally, our General Partner’s board of directors generally reviews and discusses the Compensation Discussion and Analysis with the management of our General Partner as a part of our governance practices. Based on this review and discussion, our General Partner’s board of directors, with the concurrence of the Management Committee, has directed that the Compensation Discussion and Analysis be included in this annual report for filing with the SEC. Members of the Board of Directors of Crestwood Gas Services GP LLC Alvin Bledsoe Timothy H. Day Michael G. France Joel C. Lambert Thomas F. Darden Philip D. Gettig J. Hardy Murchison Robert G. Phillips John W. Somerhalder II 91 Summary Compensation Table The following table sets forth certain information regarding the compensation provided by us in 2010, 2009 and 2008 to the (i) current and former Chief Executive Officer of our General Partner, (ii) the current and former Chief Financial Officer of our General Partner, (iii) the four most highly-compensated executive officers of our General Partner who were serving in such capacity at the end of December 31, 2010, (iv) two most highly- compensated individuals who were not serving as executive officers of our General Partner at the end of December 31, 2010. These ten individuals are referred to as “named executive officers” in the tables that follow: Name and Principal Position Robert G. Phillips(2). . . . . . . . . . . . . . . . . . . . President, Chief Executive Officer and Chairman of the Board Thomas F. Darden(3) . . . . . . . . . . . . . . . . . . . President and Chief Executive Officer William G. Manias(2) . . . . . . . . . . . . . . . . . . . Senior Vice President — Chief Financial Officer Philip W. Cook(3). . . . . . . . . . . . . . . . . . . . . . Senior Vice President — Chief Financial Officer Terry M. Morrison(2) . . . . . . . . . . . . . . . . . . . Senior Vice President — Business Development Joel D. Moxley(2). . . . . . . . . . . . . . . . . . . . . . Senior Vice President — Operations and Commercial Eric Guy . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vice President — Controller Mark G. Stockard(2) . . . . . . . . . . . . . . . . . . . . Vice President, Treasurer and Assistant Secretary Glenn Darden(3) . . . . . . . . . . . . . . . . . . . . . . . Chairman of the Board Jeff Cook(3) . . . . . . . . . . . . . . . . . . . . . . . . . . Executive Vice President — Chief Operating Officer Year 2010 2009 2008 2010 2009 2008 2010 2009 2008 2010 2009 2008 2010 2009 2008 2010 2009 2008 2010 2009 2008 2010 2009 2008 2010 2009 2008 2010 2009 2008 Salary ($) 100,000 — — — — — 62,500 — — — — — 62,500 — — 62,500 — — 133,000 — — 55,000 — — — — — — — — Bonus ($) Equity Awards ($)(1) — 200,000 — — — — — 807,549 — 832,173 — 752,778 — 125,000 — — — — — 312,597 — 322,131 — 298,405 — 125,000 — — — — — 125,000 — — — — 125,490 12,000 — — — — 245,183 27,500 — — — — — 807,549 — 832,173 — 752,778 — 377,718 — 389,242 — 379,785 Other ($)(4) Total ($) — 300,000 — — — — — 807,549 — 832,173 — 752,778 — 187,500 — — — — — 312,597 — 322,131 — 298,405 — 187,500 — — — — — 187,500 — — — — 327,300 56,810 — — — — — 327,683 — — — — — 807,549 — 832,173 — 752,778 — 377,718 — 389,242 — 379,785 (1) This column reports the aggregate grant date fair value of the phantom unit awards granted in 2010, 2009 and 2008 computed in accordance with FASC Topic 718. Additional information regarding the calculation of these amounts is included in Notes 2 and 11 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this annual report and our annual reports for the respective year end. (2) This individual joined the General Partner effective October 1, 2010. Consequently, the information presented represents the period Post-Crestwood Transaction of October 1, 2010 to December 31, 2010. (3) In connection with the closing of the Crestwood Transaction, this individual resigned from the General Partner effective October 1, 2010. Mr. Thomas F. Darden continues to serve on the board of directors of our General Partner. (4) In connection with the closing of the Crestwood Transaction, Mr. Guy received a separation payment from Quicksilver. 92 Grants of Plan-Based Awards in 2010 The following table sets forth certain information regarding grants of awards under our 2007 Equity Plan made to the named executive officers in 2010. Each of these grants consists of phantom units that vest one-third on January 15th or on the first business day occurring on or after each of the first three anniversaries of the date of grant (or if earlier, the named executive officer’s death or disability or a change-in-control) and are to be settled in common units immediately upon vesting. Name Grant Date Robert G. Phillips . . . . . . . . . . . . . . . . . 12/10/2010 Thomas F. Darden. . . . . . . . . . . . . . . . . 1/4/2010 William G. Manias . . . . . . . . . . . . . . . . 12/10/2010 1/4/2010 Philip W. Cook . . . . . . . . . . . . . . . . . . . — Terry M. Morrison . . . . . . . . . . . . . . . . Joel D. Moxley . . . . . . . . . . . . . . . . . . . — 1/4/2010 Eric Guy . . . . . . . . . . . . . . . . . . . . . . . 12/10/2010 Mark G. Stockard . . . . . . . . . . . . . . . . . 12/10/2010 1/4/2010 Glenn Darden . . . . . . . . . . . . . . . . . . . . 1/4/2010 Jeff Cook . . . . . . . . . . . . . . . . . . . . . . . Board Approval Date 11/10/2010 12/19/2009 11/10/2010 12/19/2009 — — 12/19/2009 11/10/2010 11/10/2010 12/19/2009 12/19/2009 Equity Awards Number of Units: (#) Grant Date Fair Value of Equity Awards ($)(1) — 38,182 — 14,780 — — 1,788 3,234 9,044 38,182 17,859 — 807,549 — 312,597 — — 37,816 87,674 245,183 807,549 377,718 (1) This column reports the grant date fair value of the phantom unit awards granted in 2010 computed in accordance with FASC Topic 718. Additional information regarding the calculation of these amounts is included in Notes 2 and 11 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this annual report. Outstanding Equity Awards at Year-End 2010 The following table sets forth information regarding the holdings of phantom unit awards by the named executive officers at December 31, 2010. No options with regard to our units have been granted to our named executive officers. Name Robert G. Phillips . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thomas F. Darden . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . William G. Manias . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Philip W. Cook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Terry M. Morrison. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Joel D. Moxley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Eric Guy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mark G. Stockard . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Glenn Darden . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Jeff Cook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity Awards in Units Number of Shares or Units of Stock That Have Not Vested (#) Market Value of Shares or Units of Stock that have not Vested ($)(1) —(3) —(2) —(3) —(2) —(3) —(3) 3,234(4) 9,044(4) —(2) —(2) — — — — — — 87,932 245,906 — — (1) The market value of phantom unit awards is based on $27.19, the closing market price of CMLP common units on December 31, 2010. 93 (2) All units vested with the change in control due to the Crestwood Transaction. (3) Does not receive units. (4) One-third of these units will vest on each January 15, 2012, 2013 and 2014. Stock Vested in 2010 The following table sets forth information regarding the units held by named executive officers that vested during 2010. Name Robert G. Phillips . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thomas F. Darden . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . William G. Manias . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Philip W. Cook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Terry M. Morrison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Joel D. Moxley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Eric Guy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mark G. Stockard . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Glenn Darden. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Jeff Cook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity Awards Number of Shares or Units Acquired on Vesting (#) — (1) 144,111 (2) — (1) 56,346 (3) — (1) — (1) 7,265 (4) — (1) 144,111 (2) 68,245 (5) Value Realized on Vesting ($) (1) — 3,421,677 — 1,337,287 — — 171,675 — 3,421,677 1,619,657 (1) No units vested in 2010. (2) On January 4, 2010, 37,511 of each of Messrs. Darden’s phantom units, which settled in units, vested when the market price was $21.15. On August 10, 2010, 3,333 of each of Messrs. Darden’s phantom units, which settled in cash, vested when the market price was $22.67. On October 1, 2010, 103,267 of each of Messrs. Darden’s phantom units, which settled in units, vested when the market price was $24.72. (3) On January 4, 2010, 14,613 of Mr. Cook’s phantom units, which settled in units, vested when the market price was $21.15. On August 10, 2010, 1,667 of Mr. Cook’s phantom units, which settled in cash, vested when the market price was $22.67. On October 1, 2010, 40,066 of Mr. Cook’s phantom units, which settled in units, vested when the market price was $24.72. (4) On January 4, 2010, 1,739 of Mr. Guy’s phantom units, which settled in units, vested when the market price was $21.15. On August 10, 2010, 833 of Mr. Guy’s phantom units, which settled in cash, vested when the market price was $22.67. On October 1, 2010, 4,693 of Mr. Guy’s phantom units, which settled in units, vested when the market price was $24.72. (5) On January 4, 2010, 17,911 of Mr. Cook’s phantom units, which settled in units, vested when the market price was $21.15. On August 10, 2010, 1,667 of Mr. Cook’s phantom units, which settled in cash, vested when the market price was $22.67. On October 1, 2010, 48,667 of Mr. Cook’s phantom units, which settled in units, vested when the market price was $24.72. Potential Payments upon Termination or Change-in-Control Upon a named executive officer’s termination by reason of death or disability or upon a change-in-control as defined under the 2007 Equity Plan, as amended, such named executive officer’s outstanding unvested equity awards granted under the 2007 Equity Plan, as amended, would immediately vest. The payments set forth in the table are based on the assumption that the event occurred on December 31, 2010, the last business day of 2010. The amounts shown in the table do not include payments and benefits that could be received by such individual from Crestwood. 94 Name Robert G. Phillips . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thomas F. Darden . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . William G. Manias . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Philip W. Cook. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Terry M. Morrison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Joel D. Moxley. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Eric Guy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mark G. Stockard . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Glenn Darden . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Jeff Cook . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equity Awards(1) Number of Shares or Units of Stock that have not Vested (#) Market Value of Shares or Units of Stock that have not Vested and will Vest upon a Triggering ($)(2) — — — — — — 3,234 9,044 — — — — — — — — 87,932 245,906 — — (1) Includes phantom units that will be settled in units upon vesting. (2) The market value of unit awards is based on $27.19, the closing market price of our common units on December 31, 2010. Director Compensation for 2010 Directors of our General Partner who are also employees of Crestwood are not separately compensated for their services as directors. For the year ended 2010, each of our non-employee directors was entitled to receive a fee of $100,000, payable 50% in phantom units and 50% in cash (subject to their elections to receive phantom units in lieu of some or all of the cash portion). Each of these phantom unit awards was granted under our 2007 Equity Plan and settles in units upon vesting. The following table sets forth certain information regarding the compensation of the non-employee directors of our General Partner. Name Fees Earned or Paid in Cash ($)(1) Equity Awards ($)(2) Alvin Bledsoe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thomas F. Darden . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Timothy H. Day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Philip D. Gettig . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Michael G. France . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Joel C. Lambert . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . J. Hardy Murchison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Robert G. Phillips . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . John W. Somerhalder II . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50,000 — — 40,000 — — — — — 49,999(3) —(6) —(6) 60,003(4) —(6) —(6) —(6) —(6) 99,997(5) Total ($) 99,999 — — 100,003 — — — — 99,997 (1) This column reports the aggregate compensation earned in 2010 and paid in cash and excludes $50,000 that Mr. Somerhalder elected to receive in the form of phantom units. (2) This column reports the grant date fair value of the phantom unit awards granted in 2010 computed in accordance with FASC Topic 718. Additional information regarding the calculation of these amounts is included in Notes 2 and 11 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this annual report. 95 (3) The grant date fair value calculated for the 2,364 phantom units granted to Mr. Bledsoe in 2010. As of December 31, 2010, Mr. Bledsoe did not have any unvested phantom units due to the change of control with the Crestwood Transaction. (4) The grant date fair value calculated for the 2,837 phantom units granted to Mr. Gettig in 2010. As of December 31, 2010, Mr. Gettig did not have any unvested phantom units due to the change of control with the Crestwood Transaction. (5) The grant date fair value calculated for the 4,728 phantom units granted to Mr. Somerhalder in 2010, including those phantom units he acquired in lieu of $50,000 in cash fees. As of December 31, 2010, Mr. Somerhalder did not have any unvested phantom units due to the change of control with the Crestwood Transaction. (6) Waived compensation for 2010. Compensation Committee Interlocks and Insider Participations Our General Partner does not have a compensation committee. In the Pre-Crestwood Transaction period, Messrs. Glenn Darden, Thomas Darden, Jeff Cook and Philip W. Cook, each of whom was an executive officer of our General Partner, participated in his capacity as a director in the deliberations of the board of directors of our General Partner concerning executive officer compensation. In addition during that period, Mr. Thomas Darden made recommendations on behalf of the management of our General Partner to the board of directors of our General Partner regarding Pre-Crestwood Transaction executive officer compensation. Messrs. Glenn Darden and Thomas Darden also served as directors of Quicksilver, and Messrs. Glenn Darden, Thomas Darden, Jeff Cook and Philip W. Cook served as executive officers of Quicksilver. In the Post-Crestwood Transaction period, Mr. Robert Phillips, who serves the President, Chief Executive Officer and Chairman of our General Partner, participated in his capacity as a director in the deliberations of the Management Committee concerning executive officer compensation. In addition, during that period, Mr. Phillips made recommendations on behalf of the management of our General Partner to the Management Committee regarding Post-Crestwood Transaction named executive officer compensation but abstained from any decisions regarding his compensation. 96 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Crestwood Midstream Partners LP The following table sets forth certain information regarding the beneficial ownership of our common and subordinated units as of February 14, 2011 by: (cid:129) each person known by us to beneficially own more than 5% of our common or subordinated units; (cid:129) each named executive officer of Crestwood Gas Services GP LLC; (cid:129) each director of Crestwood Gas Services GP LLC; and (cid:129) all directors and executive officers of Crestwood Gas Services GP LLC as a group. Unless otherwise indicated by footnote, the beneficial owner exercises sole voting and investment power over the units. The percentages of beneficial ownership are calculated on the basis of 31,187,696 common units outstanding as of February 14, 2011. The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. Name of Beneficial Owner(1) Common Units Percentage of Common Units Crestwood Holdings Partners, LLC(2)(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,544,089 Crestwood Gas Services Holdings LLC(3)(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,544,089 2,095,679 Kayne Anderson Capital Advisors, L.P.(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53,954 Alvin Bledsoe(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Timothy H. Day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103,199 Thomas F. Darden(7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Michael G. France . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,932 Philip D. Getting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Joel C. Lambert . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — J. Hardy Murchison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26,694 John W. Somerhalder II . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Robert G. Phillips . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — William G. Manias . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Terry M. Morrison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Joel D. Moxley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Kelly J. Jameson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,206 Eric Guy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,042 Mark G. Stockard . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 208,027 Directors and executive officers as a group total 15 . . . . . . . . . . . . . . . . . . . . . . * Indicates less than 1% 62.7% 62.7% 6.7% * * * * * * 0.7% (1) Unless otherwise indicated, the address for all beneficial owners in this table is 717 Texas Avenue, Suite 3150, Houston, Texas 77002. (2) Crestwood Holding Partners, LLC is the ultimate parent company of Crestwood Gas Services Holdings LLC (“Holdings”) and may, therefore, be deemed to beneficially own the units held by Holdings. 97 (3) Holdings, an indirect wholly owned subsidiary of Crestwood, owns a 100% interest in our General Partner and a 62.7% limited partner interest in us. (4) Crestwood has shared voting power and shared investment power with Holdings, Crestwood Holdings LLC, Crestwood Holdings II LLC, FR XI CMP Holdings LLC, FR Midstream Holdings LLC, First Reserve GP XI, L.P., First Reserve GP XI, Inc., and William E. Macaulay over 19,544,089 common units of Crestwood Midstream Partners LP. Crestwood Gas Services GP LLC, the sole general partner of Crestwood Midstream Partners LP, owns a 1.5% general partner interest and incentive distribution rights (which represent the right to receive increasing percentages of quarterly distributions in excess of specified amounts) in Crestwood Midstream Partners LP. (5) According to a Schedule 13G filed by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne with the SEC on February 9, 2011, Kayne Anderson Capital Advisors, L.P. together with Richard A. Kayne has shared voting and dispositive power over 2,095,679 common units. The address of Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne is 1800 Avenue of the Stars, Second Floor, Los Angeles, California 90067. (6) Includes 200 common units over which Mr. Bledsoe exercises shared investment power. (7) Includes 76,100 common units held in a trust for which he has shared voting and investment power as a co- trustee. Mr. Darden disclaims beneficial ownership of the common units held in this trust, except to the extent of this pecuniary interest therein. Equity Compensation Plan Information The following table sets forth information as of December 31, 2010, with respect to shares of common stock that may be issued under our existing equity compensation plans. Plan Category Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a) Weighted-average Exercise Price of Outstanding Options, Warrants and Rights (b) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in Column (a)) (c) Equity compensation plans approved by security holders(1) . . . . . . . . . . . . . . . . 117,484 Equity compensation plans not approved by security holders . . . . . . . . . . . . . . . — Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117,484 (1) Consists of the 2007 Equity Plan. N/A(2) — N/A(2) 750,000 — 750,000 (2) Only phantom units have been issued under the 2007 Equity Plan. Each phantom unit entitles the holder to receive one common unit (or an amount in cash equal to the fair market value thereof) with respect to each phantom unit at vesting. Accordingly, without payment of cash, there is no reportable weighted-average exercise price. Item 13. Certain Relationships and Related Transactions, and Director Independence General As of February 14, 2011, our General Partner and its affiliates owned 19,544,089 common units representing an aggregate 62.7% limited partner interest in us. In addition, as of February 14, 2011, our General Partner owned approximately a 1.5% general partner interest in us and all of the incentive distribution rights. We and our General Partner and its affiliates are also parties to various contractual arrangements. The terms of these arrangements are not the result of arm’s length negotiations. 98 Distributions and Payments to Our General Partner and its Affiliates We make cash distributions of approximately 98% to our unitholders pro rata, including our General Partner and its affiliates, as the holders of an aggregate 19,544,089 common, and 1.5% to our General Partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our General Partner is entitled to increasing percentages of the distributions, up to 48% of the distributions above the highest target distribution level. Assuming we have sufficient available cash to maintain the current level of quarterly distribution on all of our outstanding units for four quarters, our General Partner and its affiliates would receive an annual distribution of approximately $3.5 million on their general partner interest and incentive distribution rights and $53.6 million on their common limited partner units. For 2010 the general partner and its affiliates were paid $31.3 million when taking into account amounts paid to Quicksilver during the pre-Crestwood Transaction period and amounts paid to Crestwood during the Post-Crestwood Transaction period. Property Transactions with Quicksilver On June 5, 2007, our Predecessor sold several pipeline and gathering assets to Crestwood including a portion of the gathering lines in the Cowtown Pipeline. All assets conveyed, including the portion of the gathering lines in the Cowtown Pipeline were subject to repurchase by us from Crestwood. 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, the 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. 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. Omnibus Agreement We have entered into an Omnibus Agreement with Crestwood and our General Partner that addresses the following matters: (cid:129) restrictions on Crestwood’s ability to engage in certain midstream business activities or own certain related assets in the Crestwood Counties; (cid:129) Crestwood’s obligation to indemnify us for certain liabilities and our obligation to indemnify Crestwood for certain liabilities; (cid:129) our obligation to reimburse Crestwood for all expenses incurred by Crestwood (or payments made on our behalf) in conjunction with Crestwood’s provision of general and administrative services to us, including salary and benefits of Crestwood personnel, our public company expenses, general and administrative expenses and salaries and benefits of our executive management who are Crestwood’s employees; (cid:129) our obligation to reimburse Crestwood for all insurance coverage expenses it incurs or payments it makes with respect to our assets; and (cid:129) our obligation to reimburse Crestwood for all expenses incurred by Crestwood (or payments made on our behalf) in conjunction with Crestwood’s provision of services necessary to operate, manage and maintain our assets. The table below reflects the categories of expenses for which we were obligated to (i) reimburse Quicksilver pursuant to the old omnibus agreement (See Note 12 to our consolidated financial statements included in Item 8 of this annual report), which includes the amounts for each category that we paid to Quicksilver Pre-Crestwood Transaction in 2010, (ii) reimburse Crestwood pursuant to the Omnibus Agreement which includes the amounts for 99 each category that we paid to Crestwood Post-Crestwood Transaction in 2010; and (iii) and an estimate of the amounts for each category that we expect to pay Crestwood in 2011. Pre-Crestwood 2010 Post-Crestwood 2010 Estimates for 2011 (In millions) Reimbursement of general and administrative expenses . . . . . . . . . . . $2.0 Reimbursement of public company expenses . . . . . . . . . . . . . . . . . . . . . . Reimbursement of compensation and benefits for Crestwood personnel . . . . Reimbursement of compensation and benefits for executive management of our General Partner . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . 2.1 — 0.2 $4.3 $ — 0.2 3.2 1.0 $4.4 $ — — 10.8 2.5 $13.3 Our General Partner and its affiliates will also receive payments from us pursuant to the contractual arrangements described below under the caption “— Contracts with Affiliates.” Any or all of the provisions of the Omnibus Agreement are terminable by Crestwood at its option if our General Partner is removed without cause and units held by our General Partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement will also generally terminate in the event of a change of control of us or our General Partner. Reimbursement of Operating and General and Administrative Expense Under the Omnibus Agreement, we will reimburse Crestwood for the payment of certain operating expenses and for the provision of various general and administrative services for our benefit with respect to our assets. The Omnibus Agreement further provides that we will reimburse Crestwood for all expenses it incurs or payments it makes with respect to our assets. Pursuant to these arrangements, Crestwood performs centralized corporate functions for us, such as legal, accounting, treasury, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. Generally, these allocations are based on the amount of time individuals performing these functions devote to our business and affairs relative to the amount of time that we believe they devote to Crestwood’s business and affairs. Reimbursement for Operations Services Expenses Under the Omnibus Agreement, we will reimburse Crestwood for all expenses incurred by our on our behalf in conjunction with services provided by Crestwood that are necessary to operate, manage and maintain our assets. Such services include, but are not limited to, salaries and other wages of Crestwood personnel performing such services (the “Operations Personnel”), (ii) bonus amounts paid to Operations Personnel, (iii) paid time off, benefits granted to Operations Personnel, (iv) employee benefits to Operations Personnel, (v) grants of cash for settled phantom units, if any, (vi) severance payments, if any, (vii) workers compensation insurance, and (viii) any of the employee costs or benefits relating to Operations Personnel for which Crestwood incurs costs. Indemnification Under the omnibus agreement, we have agreed to indemnify Quicksilver for all losses attributable to the post- closing operations of the gathering and processing business contributed to us at the closing of our IPO unless in any such case indemnification would not be permitted under our Partnership Agreement. Competition Under the Omnibus Agreement, Crestwood has agreed that, subject to specified exceptions, it will not engage in the restricted businesses in the Crestwood Counties. As used in that agreement, “restricted businesses” include the gathering, treating, processing, fractionating, transportation or storage of natural gas, or the transportation or storage of natural gas liquids. Although the exceptions referred to above include Crestwood’s right to acquire assets or businesses, that include restricted businesses, Crestwood has agreed to offer us the right to acquire any such 100 midstream business assets for their construction costs, in the case of constructed assets, or fair market value, in the case of acquired assets. Furthermore, that offer would be required to be made not more than 120 days after Crestwood’s construction or acquisition of those assets or construction and the commencement of service. Except as described in the immediately preceding paragraph, neither Crestwood nor any of its affiliates will be restricted, under either the Partnership Agreement or the Omnibus Agreement, from competing with us. Subject to the preceding paragraph, Crestwood and any of its affiliates may acquire, construct or dispose of additional midstream business assets or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. The competition and business opportunity restriction provisions under the Omnibus Agreement will terminate on the earlier of August 10, 2017 and such time as Crestwood or its affiliates cease to own a majority interest in our General Partner. Contracts with Affiliates Agreements with Related Parties Detailed description of our agreements with related parties can be found in Note 12 to the consolidated financial statements included in Item 8 of this annual report, which is incorporated herein by reference. Equity Awards to Certain Quicksilver Executive Officers On November 19, 2009, the board of directors of our General Partner granted phantom units, effective January 4, 2010, under our 2007 Equity Plan to Anne Darden Self, the sister of Glenn Darden and Thomas Darden and the Vice President — Human Resources of Quicksilver, with a value on the date of grant of approximately $104,000. These grants did not require review by the conflicts committee of our General Partner under our related- party transaction policy. For further information regarding the policy, see below “Policies and Procedures for Review and Approval of Transactions with Related Parties.” Policies and Procedures for Review and Approval of Transactions with Related Parties Our General Partner’s board of directors has adopted a written policy covering transactions with related parties pursuant to which it has delegated to the conflicts committee the responsibility for reviewing and, if appropriate, approving or ratifying such transactions. The policy covers transactions to which we or any of our subsidiaries is a party and in which any director or executive officer of our General Partner or any person that beneficially owns more than 5% of our common units, any immediate family member of such director, officer or owner, or any related entity of such related party, had, has or will have a direct or indirect interest, other than a transaction involving (a) compensation by us or (b) less than $120,000. The policy instructs directors and executive officers to bring any possible related-party transaction to the attention of our General Partner’s General Counsel or Compliance Officer, who, unless he or she determines that the transaction is not a related-party transaction, will notify the chairman of the conflicts committee. The conflicts committee reviews each related-party transaction of which it becomes aware and may approve or ratify a related-party transaction if the conflicts committee determines that the transaction is in the best interest of us and our unitholders. In making this determination, the conflicts committee considers (i) whether the terms of the transaction are more or less favorable to us than those that could be expected to be obtained from an unrelated third party on an arm’s length basis (ii) any provisions in our financing arrangements relating to transactions with related parties or affiliates; and (iii) any other matters the committee deems relevant and appropriate. The conflicts committee reports periodically to our General Partner’s board of directors on the nature of the transactions with related parties that have been presented to the conflicts committee and the determinations that the conflicts committee has made with respect to those transactions. Director Independence Our General Partner’s board of directors has adopted categorical independence standards consistent with the current listing standards of the NYSE to assist the board of directors in determining which of its members is independent. A copy of the categorical independence standards appears in the Corporate Overview section under 101 Corporate Governance of our website www.crestwoodlp.com. Our General Partner’s board of directors has determined that each of Messrs. Bledsoe, Gettig and Somerhalder satisfies our General Partner’s categorical independence standards and further determined that each of them is independent within the meaning of NYSE listing standards. The NYSE does not require a listed limited partnership like us to have a majority of independent directors, a compensation committee or a nominating and governance committee. Accordingly, each director of Crestwood Gas Services GP LLC may participate in consideration of compensation, nomination and governance matters. Presiding Non-Management Director and Executive Sessions Our General Partner’s non-management directors meet in executive session without management either before or after regularly scheduled board meetings. In May 2009, our General Partner’s board of directors elected John W. Somerhalder II as Presiding Non-Management Director, in accordance with the NYSE rules. In his capacity as Presiding Non-Management Director, Mr. Somerhalder’s primary responsibility is to preside over regularly scheduled executive sessions of the non-management directors of our General Partner. Communication with the Board Any interested party who wishes to communicate directly with our General Partner’s board of directors or any of its members may do so by writing to: Board of Directors (or one or more named individuals), Crestwood Midstream Partners LP, 717 Texas Avenue, Suite 3150, Houston, Texas 77002. Additionally, any interested party can contact the non-management directors at (832) 519-2200. Item 14. Principal Accountant Fees and Services The following sets forth fees billed by Deloitte & Touche LLP for the audit of our annual financial statements and other services rendered for the years ended December 31, 2010 and 2009: Fees Billed For The Year Ended December 31, 2010 2009 Audit fees(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $272,467 — Audit-related fees(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Tax fees(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — All other fees(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $353,766 — — 172,836 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $272,467 $526,602 (1) Includes fees for audits of annual financial statements and reviews of the related quarterly financial statements. (2) There were no audit-related fees for 2010 or 2009. (3) There were no tax fees billed for 2010 or 2009. (4) Includes fee related to the equity offering for 2009. Pursuant to its charter, the audit committee is responsible for the oversight of our accounting, reporting and financial practices. The audit committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors and to pre-approve all audit and non-audit services. The audit committee has delegated to its chairman the responsibility to pre-approve all audit and non-audit services, provided that these decisions are presented to the full audit committee at its next regularly scheduled meeting. 102 PART IV Item 15. Exhibits and Financial Statement Schedules The following documents are filed as part of this report: 1. Financial Statements: The following financial statements of ours and the report of our Independent Auditors thereon are included on pages 52 through 78 of this Form 10-K. Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets as of December 31, 2010 and 2009 Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008 Consolidated Statements of Partners’ Capital for the years ended December 31, 2010, 2009 and 2008 Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008 Notes to Consolidated Financial Statements for the Years Ended December 31, 2010, 2009 and 2008 2. Financial Statement Schedules: All schedules are omitted because the required information is inapplicable or the information is presented in the financial statements or the notes thereto. 3. Exhibits: Exhibit No. Description 2.1 2.2 2.3 3.1 3.2 3.3 3.4 3.5 3.6 Purchase and Sale Agreement, dated December 10, 2009, among Cowtown Pipeline L.P., Quicksilver Gas Services LP and Cowtown Pipeline Partners L.P. (filed as Exhibit 10.1 to the Company’s Form 8-K filed December 10, 2009 and included herein by reference). Letter Agreement, dated December 29, 2009, among Cowtown Pipeline L.P., Quicksilver Gas Services LP and Cowtown Pipeline Partners L.P. (filed as Exhibit 2.2 to the Company’s Form 10-K for the year ended December 31, 2009, filed on March 15, 2010 and included herein by reference). Purchase and Sale Agreement by and between Frontier Gas Services, LLC and Crestwood Midstream Partners LP, dated as of February 18, 2011 (included as Exhibit 2.1 to the Company’s Form 8-K filed February 22, 2011 and included herein by reference). Certificate of Limited Partnership of Quicksilver Gas Services LP (filed as Exhibit 3.1 to the Company’s Form S-1, File No. 33-140599, filed February 12, 2007 and included herein by reference). Certificate of Amendment to the Certificate of Limited Partnership of Quicksilver Gas Services LP (filed as Exhibit 3.1 to the Company’s Form 8-K, filed October 7, 2010 and included herein by reference) First Amendment to the Second Amended and Restated Agreement of Limited Partnership of Quicksilver Gas Services LP (filed as Exhibit 3.2 to the Company’s Form 10-Q for the Quarter ended September 30, 2010, filed on November 8, 2010 and included herein by reference) Second Amended and Restated Agreement of Limited Partnership of Quicksilver Gas Services LP, dated February 19, 2008 (filed as Exhibit 3.1 to the Company’s Form 8-K filed February 22, 2008 and included herein by reference). Certificate of Formation of Quicksilver Gas Services GP LLC (filed as Exhibit 3.3 to the Company’s Form S-1, File No. 333-140599, filed February 12, 2007 and included herein by reference). Certificate of Amendment to the Certificate of Formation of Quicksilver Gas Services GP LLC (filed as Exhibit 3.3 to the Company’s Form 10-Q for the Quarter ended September 30, 2010, filed on November 8, 2010 and included herein by reference). 103 Exhibit No. Description 3.7 3.8 4.1 10.1 First Amended and Restated Limited Liability Company Agreement of Quicksilver Gas Services GP LLC, dated July 24, 2007 (filed as Exhibit 3.4 to the Company’s Form S-1/A, File No. 333-140599, filed July 25, 2007 and included herein by reference). First Amendment to the First Amended and Restated Limited Liability Company Agreement of Quicksilver Gas Services GP LLC, dated July 24, 2007 (filed as Exhibit 3.4 to the Company’s Form 10-Q for the quarter ended September 30, 2010, filed on November 8, 2010 and included herein by reference) Form of Common Unit Certificate (filed as Exhibit 4.1 to the Company’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference). Assignment and Conveyance, effective April 30, 2007, between Cowtown Pipeline Partners L.P. and Cowtown Pipeline L.P. (filed as Exhibit 10.13 to the Company’s Form S-1/A, File No. 333-140599, filed July 30, 2007 and included herein by reference). 10.2(a) Form of Assignment, effective April 30, 2007, between Cowtown Pipeline Partners L.P. and to the Company’s Form S-1/A, File Cowtown Pipeline L.P. No. 333-140599, filed July 30, 2007 and included herein by reference). (filed as Exhibit 10.14(a) 10.2(b) Schedule of Assignments, effective April 30, 2007, between Cowtown Pipeline Partners L.P. and to the Company’s Form S-1/A, File (filed as Exhibit 10.14(b) 10.3 10.4 10.5 * # 10.6 10.7 10.8 10.9 10.10 10.11 Cowtown Pipeline L.P. No. 333-140599, filed July 30, 2007 and included herein by reference). Credit Agreement, dated as of August 10, 2007, among Quicksilver Gas Services LP and the lenders and agents identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 16, 2007 and included herein by reference). First Amendment to Credit Agreement, dated as of October 10, 2008, among Quicksilver Gas Services LP and the lenders and agents identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed October 14, 2008 and included herein by reference). Second Amendment to Credit Agreement, dated as of October 22, 2009, among Quicksilver Gas Services LP and the lenders and agents identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed October 22, 2009 and included herein by reference). Credit Agreement, dated as of October 1, 2010, among Crestwood Midstream Partners LP (f/k/a Quicksilver Gas Services LP), BNP Paribas as administrative agent and collateral agent, Banc of America Securities LLC, BNP Paribas Securities Corp. and RBC Capital Markets Corporation, as joint lead arrangers and joint bookrunners, Bank of America, N.A. and Royal Bank of Canada, as syndication agents, and UBS Securities and The Royal Bank of Scotland PLC as co-documentation agents. Subordinated Promissory Note, dated as of August 10, 2007, made by Quicksilver Gas Services LP payable to the order of Quicksilver Resources Inc. (filed as Exhibit 10.2 to the Company’s Form 8-K filed August 16, 2007 and included herein by reference). Omnibus Agreement, dated August 10, 2007, among Quicksilver Gas Services LP, Quicksilver Gas Services GP LLC and Quicksilver Resources Inc. (filed as Exhibit 10.4 to the Company’s Form 8-K filed August 16, 2007 and included herein by reference). Omnibus Agreement, dated October 8, 2010, by and among Crestwood Midstream Partners LP, Crestwood Gas Services GP LLC and Crestwood Holdings Partners, LLC (filed as Exhibit 3.1 to the Company’s Form 8-K filed October 13, 2010 and included herein by reference). Extension Agreement, dated December 3, 2008, between Quicksilver Gas Services LP and Quicksilver Resources Inc. (filed as Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2009, filed on March 15, 2010). Option, Right of First Refusal, and Waiver in Amendment to Omnibus Agreement and Gas Gathering and Processing Agreement, dated as of June 9, 2009, among Quicksilver Resources Inc., Quicksilver Gas Services LP, Quicksilver Gas Services GP LLC, Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (filed as Exhibit 10.1 to the Company’s Form 8-K filed June 11, 2009 and included herein by reference). 10.12 Waiver, dated November 19, 2009, by Quicksilver Gas Services GP LLC (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 23, 2009 and included herein by reference). 104 Exhibit No. Description 10.13 Waiver, dated November 19, 2009, by Quicksilver Resources Inc. (filed as Exhibit 10.2 to the 10.14 10.15 *10.16 10.17 *10.18 10.19 *10.20 10.21 +*10.22 +*10.23 +*10.24 +*10.25 +*10.26 +*10.27 +*10.28 *21.1 *23.1 *31.1 *31.2 *32.1 Company’s Form 8-K filed November 23, 2009 and included herein by reference). Contribution, Conveyance and Assumption Agreement, dated August 10, 2007, among Quicksilver Gas Services LP, Quicksilver Gas Services GP LLC, Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Quicksilver Gas Services Holdings LLC, Quicksilver Gas Services Operating GP LLC, Quicksilver Gas Services Operating LLC and the private investors named therein (filed as Exhibit 10.3 to the Company’s Form 8-K filed August 16, 2007 and included herein by reference). Sixth Amended and Restated Gas Gathering and Processing Agreement, dated September 1, 2008, among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (filed as Exhibit 10.1 to the Company’s Form 10-Q filed November 6, 2008 and included herein by reference). Second Amendment to the Sixth Amended and Restated Gas Gathering and Processing Agreement, dated as of October 1, 2010, by and among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. Gas Gathering Agreement, effective December 1, 2009, between Cowtown Pipeline L.P. and Quicksilver Resources Inc. (filed as Exhibit 10.1 to the Company’s Form 8-K filed on January 8, 2010 and included herein by reference). Amendment to Gas Gathering Agreement, dated as of October 1, 2010, by and between Quicksilver Resources Inc. and Cowtown Pipeline Partners L.P. Addendum and Amendment to Gas Gathering and Processing Agreement Mash Unit Lateral, effective as of January 1, 2009, among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (filed as Exhibit 10.15 to the Company’s Form 10-K for the year ended December 31, 2009, filed on March 15, 2010). Joint Operating Agreement, dated October 1, 2010, but effective as of July 1, 2010, between Quicksilver Resources Inc., Quicksilver Gas Services LP and Quicksilver Gas Services GP LLC Class C Unit Purchase Agreement by and among Crestwood Midstream Partners LP and the purchasers named therein, dated as of February 18, 2011 (included as Exhibit 10.1 to the Company’s Form 8-K filed February 22, 2011 and included herein by reference). Letter Agreement dated September 7, 2010 between the Crestwood Midstream Partners LP and Mark G. Stockard. Crestwood Midstream Partners LP Third Amended and Restated 2007 Equity Plan. Form of Phantom Unit Award Agreement for Directors (3-year). Form of Phantom Unit Award Agreement for Directors (1-year). Form of Phantom Unit Award Agreement for Non-Directors (Cash). Form of Phantom Unit Award Agreement for Non-Directors (Units). Form of Indemnification Agreement by and between Crestwood Midstream Partners LP and its officers and directors. List of Subsidiaries of Crestwood Midstream Partners LP. Consent of Deloitte & Touche LLP. Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 * Filed herewith + Identifies management contracts and compensatory plans or arrangements. # Confidential treatment has been requested for certain portions which are omitted in the copy of the exhibit electronically filed with the SEC. The omitted information has been filed separately with the SEC pursuant to our application for confidential treatment. 105 Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURES CRESTWOOD GAS SERVICES LP By: CRESTWOOD GAS SERVICES GP LLC, General Partner By: /s/ ROBERT G. PHILLIPS Robert G. Phillips President and Chief Executive Officer Dated: February 25, 2011 Pursuant to the requirements of the Securities Exchange Act of 1934, the following persons on behalf of the registrant and in the capacities and on the dates indicated have signed this report below. SIGNATURE TITLE DATE /s/ ROBERT G. PHILLIPS Robert G. Phillips /s/ WILLIAM G. MANIAS William G. Manias /s/ ERIC GUY Eric Guy /s/ ALVIN BLEDSOE Alvin Bledsoe /s/ THOMAS F. DARDEN Thomas F. Darden /s/ TIMOTHY H. DAY Timothy H. Day /s/ MICHAEL G. FRANCE Michael G. France /s/ PHILIP D. GETTIG Philip D. Gettig /s/ JOEL C. LAMBERT Joel C. Lambert /s/ J. HARDY MURCHISON J. Hardy Murchison /s/ JOHN W. SOMERHALDER II John W. Somerhalder II President, Chief Executive Officer and Chairman of the Board (Principal Executive Officer) February 25, 2011 Senior Vice President — Chief Financial Officer (Principal Financial Officer) February 25, 2011 Vice President and Controller (Principal Accounting Officer) February 25, 2011 Director February 25, 2011 Director February 25, 2011 Director February 25, 2011 Director February 25, 2011 Director February 25, 2011 Director February 25, 2011 Director February 25, 2011 Director February 25, 2011 106 Exhibit No. EXHIBIT INDEX Description 2.1 2.2 2.3 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 4.1 10.1 Purchase and Sale Agreement, dated December 10, 2009, among Cowtown Pipeline L.P., Quicksilver Gas Services LP and Cowtown Pipeline Partners L.P. (filed as Exhibit 10.1 to the Company’s Form 8-K filed December 10, 2009 and included herein by reference). Letter Agreement, dated December 29, 2009, among Cowtown Pipeline L.P., Quicksilver Gas Services LP and Cowtown Pipeline Partners L.P. (filed as Exhibit 2.2 to the Company’s Form 10-K for the year ended December 31, 2009, filed on March 15, 2010 and included herein by reference). Purchase and Sale Agreement by and between Frontier Gas Services, LLC and Crestwood Midstream Partners LP, dated as of February 18, 2011 (included as Exhibit 2.1 to the Company’s Form 8-K filed February 22, 2011 and included herein by reference). Certificate of Limited Partnership of Quicksilver Gas Services LP (filed as Exhibit 3.1 to the Company’s Form S-1, File No. 33-140599, filed February 12, 2007 and included herein by reference). Certificate of Amendment to the Certificate of Limited Partnership of Quicksilver Gas Services LP (filed as Exhibit 3.1 to the Company’s Form 8-K, filed October 7, 2010 and included herein by reference) First Amendment to the Second Amended and Restated Agreement of Limited Partnership of Quicksilver Gas Services LP (filed as Exhibit 3.2 to the Company’s Form 10-Q for the Quarter ended September 30, 2010, filed on November 8, 2010 and included herein by reference) Second Amended and Restated Agreement of Limited Partnership of Quicksilver Gas Services LP, dated February 19, 2008 (filed as Exhibit 3.1 to the Company’s Form 8-K filed February 22, 2008 and included herein by reference). Certificate of Formation of Quicksilver Gas Services GP LLC (filed as Exhibit 3.3 to the Company’s Form S-1, File No. 333-140599, filed February 12, 2007 and included herein by reference). Certificate of Amendment to the Certificate of Formation of Quicksilver Gas Services GP LLC (filed as Exhibit 3.3 to the Company’s Form 10-Q for the Quarter ended September 30, 2010, filed on November 8, 2010 and included herein by reference). First Amended and Restated Limited Liability Company Agreement of Quicksilver Gas Services GP LLC, dated July 24, 2007 (filed as Exhibit 3.4 to the Company’s Form S-1/A, File No. 333-140599, filed July 25, 2007 and included herein by reference). First Amendment to the First Amended and Restated Limited Liability Company Agreement of Quicksilver Gas Services GP LLC, dated July 24, 2007 (filed as Exhibit 3.4 to the Company’s Form 10-Q for the quarter ended September 30, 2010, filed on November 8, 2010 and included herein by reference) Form of Common Unit Certificate (filed as Exhibit 4.1 to the Company’s Form S-1/A, File No. 333-140599, filed July 17, 2007 and included herein by reference). Assignment and Conveyance, effective April 30, 2007, between Cowtown Pipeline Partners L.P. and Cowtown Pipeline L.P. (filed as Exhibit 10.13 to the Company’s Form S-1/A, File No. 333-140599, filed July 30, 2007 and included herein by reference). 10.2(a) Form of Assignment, effective April 30, 2007, between Cowtown Pipeline Partners L.P. and to the Company’s Form S-1/A, File Cowtown Pipeline L.P. No. 333-140599, filed July 30, 2007 and included herein by reference). (filed as Exhibit 10.14(a) 10.2(b) Schedule of Assignments, effective April 30, 2007, between Cowtown Pipeline Partners L.P. and to the Company’s Form S-1/A, File (filed as Exhibit 10.14(b) Cowtown Pipeline L.P. No. 333-140599, filed July 30, 2007 and included herein by reference). Credit Agreement, dated as of August 10, 2007, among Quicksilver Gas Services LP and the lenders and agents identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed August 16, 2007 and included herein by reference). First Amendment to Credit Agreement, dated as of October 10, 2008, among Quicksilver Gas Services LP and the lenders and agents identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed October 14, 2008 and included herein by reference). 10.3 10.4 107 Exhibit No. 10.5 * # 10.6 10.7 10.8 10.9 10.10 10.11 Description Second Amendment to Credit Agreement, dated as of October 22, 2009, among Quicksilver Gas Services LP and the lenders and agents identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed October 22, 2009 and included herein by reference). Credit Agreement, dated as of October 1, 2010, among Crestwood Midstream Partners LP (f/k/a Quicksilver Gas Services LP), BNP Paribas as administrative agent and collateral agent, Banc of America Securities LLC, BNP Paribas Securities Corp. and RBC Capital Markets Corporation, as joint lead arrangers and joint bookrunners, Bank of America, N.A. and Royal Bank of Canada, as syndication agents, and UBS Securities and The Royal Bank of Scotland PLC as co-documentation agents. Subordinated Promissory Note, dated as of August 10, 2007, made by Quicksilver Gas Services LP payable to the order of Quicksilver Resources Inc. (filed as Exhibit 10.2 to the Company’s Form 8-K filed August 16, 2007 and included herein by reference). Omnibus Agreement, dated August 10, 2007, among Quicksilver Gas Services LP, Quicksilver Gas Services GP LLC and Quicksilver Resources Inc. (filed as Exhibit 10.4 to the Company’s Form 8-K filed August 16, 2007 and included herein by reference). Omnibus Agreement, dated October 8, 2010, by and among Crestwood Midstream Partners LP, Crestwood Gas Services GP LLC and Crestwood Holdings Partners, LLC (filed as Exhibit 3.1 to the Company’s Form 8-K filed October 13, 2010 and included herein by reference). Extension Agreement, dated December 3, 2008, between Quicksilver Gas Services LP and Quicksilver Resources Inc. (filed as Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31, 2009, filed on March 15, 2010). Option, Right of First Refusal, and Waiver in Amendment to Omnibus Agreement and Gas Gathering and Processing Agreement, dated as of June 9, 2009, among Quicksilver Resources Inc., Quicksilver Gas Services LP, Quicksilver Gas Services GP LLC, Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (filed as Exhibit 10.1 to the Company’s Form 8-K filed June 11, 2009 and included herein by reference). 10.12 Waiver, dated November 19, 2009, by Quicksilver Gas Services GP LLC (filed as Exhibit 10.1 to the Company’s Form 8-K filed November 23, 2009 and included herein by reference). 10.13 Waiver, dated November 19, 2009, by Quicksilver Resources Inc. (filed as Exhibit 10.2 to the 10.14 10.15 *10.16 10.17 *10.18 10.19 Company’s Form 8-K filed November 23, 2009 and included herein by reference). Contribution, Conveyance and Assumption Agreement, dated August 10, 2007, among Quicksilver Gas Services LP, Quicksilver Gas Services GP LLC, Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Quicksilver Gas Services Holdings LLC, Quicksilver Gas Services Operating GP LLC, Quicksilver Gas Services Operating LLC and the private investors named therein (filed as Exhibit 10.3 to the Company’s Form 8-K filed August 16, 2007 and included herein by reference). Sixth Amended and Restated Gas Gathering and Processing Agreement, dated September 1, 2008, among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (filed as Exhibit 10.1 to the Company’s Form 10-Q filed November 6, 2008 and included herein by reference). Second Amendment to the Sixth Amended and Restated Gas Gathering and Processing Agreement, dated as of October 1, 2010, by and among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. Gas Gathering Agreement, effective December 1, 2009, between Cowtown Pipeline L.P. and Quicksilver Resources Inc. (filed as Exhibit 10.1 to the Company’s Form 8-K filed on January 8, 2010 and included herein by reference). Amendment to Gas Gathering Agreement, dated as of October 1, 2010, by and between Quicksilver Resources Inc. and Cowtown Pipeline Partners L.P. Addendum and Amendment to Gas Gathering and Processing Agreement Mash Unit Lateral, effective as of January 1, 2009, among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (filed as Exhibit 10.15 to the Company’s Form 10-K for the year ended December 31, 2009, filed on March 15, 2010). 108 Exhibit No. *10.20 10.21 +*10.22 +* 10.23 +*10.24 +*10.25 +*10.26 +*10.27 +*10.28 *21.1 *23.1 *31.1 *31.2 *32.1 Description Joint Operating Agreement, dated October 1, 2010, but effective as of July 1, 2010, between Quicksilver Resources Inc., Quicksilver Gas Services LP and Quicksilver Gas Services GP LLC Class C Unit Purchase Agreement by and among Crestwood Midstream Partners LP and the purchasers named therein, dated as of February 18, 2011 (included as Exhibit 10.1 to the Company’s Form 8-K filed February 22, 2011 and included herein by reference). Letter Agreement dated September 7, 2010 between the Crestwood Midstream Partners LP and Mark G. Stockard. Crestwood Midstream Partners LP Third Amended and Restated 2007 Equity Plan. Form of Phantom Unit Award Agreement for Directors (3-year). Form of Phantom Unit Award Agreement for Directors (1-year). Form of Phantom Unit Award Agreement for Non-Directors (Cash). Form of Phantom Unit Award Agreement for Non-Directors (Units). Form of Indemnification Agreement by and between Crestwood Midstream Partners LP and its officers and directors. List of Subsidiaries of Crestwood Midstream Partners LP. Consent of Deloitte & Touche LLP. Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 * Filed herewith + Identifies management contracts and compensatory plans or arrangements. # Confidential treatment has been requested for certain portions which are omitted in the copy of the exhibit electronically filed with the SEC. The omitted information has been filed separately with the SEC pursuant to our application for confidential treatment. 109 

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