2012 Annual Report Taking the Lead in Midstream Services US Shale and Unconventional Resource Plays Niobrara Hilliard- Baxter- Mancos Mancos Bakken Gammon Mowry Utica Niobrara Antrim Monterey- Temblor Monterey Hermosa Lewis Pierre Excello- Mulky Woodford Devonian New Albany Marcellus Conasauga Avalon- Bone Spring Granite iit Wash Barnett Barnett- Woodford Fayetteville Haynesville- Bossier Eagle Ford Area with existing assets and operations Area with greenfield or development projects being evaluated Crestwood Midstream Partners LP is taking the lead in midstream services by executing its shale focused strategy through the acquisition and development of midstream assets with an organization committed to operational safety and customer service. We are actively pursuing growth opportunities around our current operating areas as well as expansion into additional resource plays with rich gas, natural gas liquids or crude oil potential. With an experienced management team, growing operations group and strong general partner sponsor, Crestwood is well positioned to participate in the long-term infrastructure build out of midstream assets that will be required to support the growing oil and gas production to supply the nation’s energy needs. Pictured on Cover, Robert Moore, Measurement Technician in the Barnett Shale region calibrates measurement devices to maintain integrity of metering equipment. Crestwood invests in state of the art measurement devices and ongoing training of its employees to ensure the accuracy of gas measurement throughout its systems. 2012 Key Strategies (cid:23)(cid:3)Expanded portfolio to six shale plays (cid:23)(cid:3)Established position in Marcellus Shale (cid:23)(cid:3)Reached critical mass of 1 Bcf/d in gathering volumes (cid:23)(cid:3)Created business development team for greenfield projects (cid:23)(cid:3)Maintained safety, reliability and customer service as key operating principles Financial and Operating Highlights Crestwood Midstream Partners LP (Dollar amounts in thousands, except per unit data) Year ended December 31 Statement of Operations Data Total revenues Adjusted EBITDA Adjusted net income Weighted average number of limited partner units outstanding (diluted basis) Balance Sheet Data Total assets Long-term debt Partners’ capital Other Financial Data Adjusted distributable cash flow Cash distributions declared per unit Operating Data Gathering (MMcf) Processing (MMcf) 2009 2010 2011 20121 $ 95,881 $113,590 $ 205,820 $ 239,463 64,238 32,499 28,189 76,549 42,748 31,316 109,962 49,782 37,320 132,465 43,956 45,420 $487,624 125,400 284,837 $570,627 $1,026,892 $1,610,469 283,504 258,753 512,500 455,623 685,161 859,609 $ 51,260 $ 1.52 $ 63,301 $ 1.66 $ $ 87,825 $ 105,082 1.87 $ 2.02 93,955 54,386 125,317 46,660 208,146 52,613 301,061 63,264 1 Data for 2012 reflects updated financial and operating information filed with the Securities and Exchange Commission on Form 8-K on March 18, 2013. This information was required as a result of Crestwood Midstream Partners LP acquiring the remaining membership interests in Crestwood Marcellus Midstream LLC (CMM) on January 8, 2013. A copy of the Form 8-K is included with this report. 1 To Our Unitholders Crestwood Midstream Partners continues to advance its goal of becoming an industry leader in midstream services to producers of natural gas, natural gas liquids (NGLs) and crude oil from shale and other unconventional resource plays. In the past three years, we have expanded Crestwood’s assets and operations from a Barnett Shale-based startup into a diversified, national midstream services provider with a focus on rich gas shale plays. This growth, through selected acquisitions and efficient integration, has created a sustainable and competitive business platform. As a result, we have been able to increase distributions paid to unitholders by over 20% since Crestwood Holdings assumed management of the partnership in the fourth quarter of 2010. Crestwood’s growing asset portfolio now comprises pipeline, processing, treating and compression assets that provide critical midstream infrastructure and services in six leading unconventional resource plays. We have also been successful in expanding our services to a growing number of top-tier shale producers. Today, more than 98% of our net revenues come from fixed-fee, long-term contracts. To complement our growing asset and customer portfolio, we have enhanced our executive management team and expanded our organization by attracting experienced midstream professionals who are committed to our principles of operational safety and best-in-class customer service. The combination of strategically located assets and dedicated employees positions Crestwood for continued success in a very competitive marketplace. In this annual report, I am pleased to profile some of our executives and employees and the role they play in providing reliable, quality services to our customers. Focus on Rich Gas Areas During 2012, we executed a well-timed strategic shift to increase our operating focus on natural gas plays that have a high-value NGL component to position Crestwood for years of continued growth. In March 2012 we acquired a gathering system in the Marcellus Shale from Antero Resources Appalachian Corporation, marking a true turning point in the execution of this strategy. The Marcellus Shale play holds the nation’s largest undeveloped natural gas reserves, including highly liquids rich areas and has some of the best drilling economics in the industry. Later, in December 2012, we expanded our presence in the Marcellus Shale with the acquisition of compression assets from Enerven Compression Services. Our large asset footprint and an experienced West Virginia operations team positions us well to support Antero and other Marcellus region producers by developing the midstream infrastructure needed to transport their rich gas production to market. We anticipate that our Marcellus assets will account for more than 40% of our overall gathering volumes and that Antero will become Crestwood’s largest customer by volume in 2013. We are highlighting our Marcellus operations in this report and the importance it will play in Crestwood’s future. 2 We also expanded our Barnett Shale rich gas assets in August 2012 with the acquisition of Devon Energy’s West Johnson County system. This transaction made Devon one of Crestwood’s largest customers and is expected to boost our processing business to approximately 15% of total revenues in 2013. Following the acquisition, we integrated the West Johnson County assets with our existing Cowtown gathering system and processing facilities. The acquisition provided substantial synergies for Crestwood, including lower operating costs and the flexibility to deploy an excess processing plant purchased in the transaction to a new rich-gas area. This transaction exemplifies the type of bolt-on acquisition strategy that we will continue to pursue in the future. Projected 2013 Gathering Volumes Crestwood’s focus on rich gas developments in 2012 positions the partnership for future growth. Our rich gas gathering systems in the Marcellus Shale, Barnett Shale, Granite Wash and Avalon/Bone Spring area of the Permian basin are expected to account for more than 65% of our total gathering volumes in 2013 and to increase at a 20% compound annual growth rate through 2017. To achieve this growth, Crestwood anticipates spending between $110 million and $140 million on expansion projects in 2013. More than 80% of this capital is dedicated to pipeline and compression projects in the Marcellus area. (cid:81) 42% Marcellus (cid:81) 20% Barnett Rich (cid:81) 4% Granite Wash (cid:81) 22% Barnett Dry (cid:81) 9% Fayetteville (cid:81) 3% Other Our shift to rich gas areas proved to be timely, as producers in the areas of our dry gas systems in the Barnett Shale, Fayetteville Shale and Haynesville Shale reduced their drilling activity due to declining natural gas prices from late 2011 to mid-2012. However, markets began to improve resulting in firmer natural gas prices by year-end 2012. Due to colder weather so far in 2013, demand is improving the long-term price outlook for natural gas. While we anticipate Crestwood’s rich gas systems to continue outpacing volumes in dry gas areas in 2013 and 2014, our dry gas systems are largely built out and efficiently run. They are well positioned for future volume growth with minimal additional capital when natural gas prices rebound to a sustained price level of $4 per MMBtu or above. Organic and Greenfield Growth Strategy With rich gas volumes increasing even faster than we expected, Crestwood achieved an operational milestone in the fourth quarter of 2012, when our total gathering volumes reached 1 Bcf per day. Attaining this goal has given Crestwood operational credibility with producers in other areas where higher crude oil and NGL prices are driving robust drilling activity and the need for new midstream infrastructure. In 2012, Crestwood implemented a complementary growth strategy by forming an in-house business development and project management team to develop “greenfield” infrastructure projects in emerging shale plays. Greenfield projects position us to get in at the ground floor of a new producing area and typically provide higher long term returns on investment than acquisitions. Our business development team has been formed with experienced professionals from companies such as El Paso, Kinder Morgan and Williams. Our team is currently developing a range of solutions for producers, including crude and gas gathering, gas processing, and NGL takeaway options through pipelines, rail and truck terminals. Looking forward, energy industry experts forecast that more than $200 billion of additional midstream infrastructure will be needed to support upstream unconventional asset development over the next 20-30 years. Having demonstrated our operational capabilities with producers, Crestwood is in excellent shape to acquire a foothold in new areas and invest in greenfield projects to meet industry demand in those areas. With the support and endorsement of First Reserve, the private equity sponsor of Crestwood’s general partner, we have established an operating platform in some of the best unconventional areas in the United States. Our near-term growth will come from our existing assets and expansion projects in rich gas areas. Long-term, our success will come from our growing reputation for solid operating and financial performance. Our strong balance sheet with continued access to a broad range of capital sources and a committed and scalable organization will also contribute to future growth. Among our many strategic and operational achievements in the past three years is Crestwood’s demonstrated ability to finance the capital required to purchase or build midstream assets. We have a solid game plan, highly experienced people, proven execution skills and a growing reputation for performance. I would like to thank our employees for their continued commitment to building a vibrant company, and want to especially thank our customers for giving Crestwood the chance to grow along with them. We remain dedicated to providing excellent system reliability and customer service, while safeguarding our employees and the environment. We believe operating Crestwood in this manner is the best way to build value for our unitholders and become an industry leader in midstream services. Robert G. Phillips Chairman, President and CEO Crestwood Gas Services GP LLC, the General Partner of Crestwood Midstream Partners LP April 4, 2013 left to right Kelly J. Jameson Senior Vice President - General Counsel and Corporate Secretary Mark G. Stockard Vice President - Investor Relations and Treasurer Joel D. Moxley Senior Vice President - Chief Operating Officer Robert G. Phillips President, Chief Executive Officer and Chairman of the Board J. Heath Deneke Senior Vice President - Chief Commercial Officer Steven M. Dougherty Senior Vice President - Interim Chief Financial Officer and Chief Accounting Officer Robert T. Halpin Vice President - Finance Gathering Volumes (Bcf) Total Revenues ($ MM) 360 300 240 180 120 60 240 200 160 120 80 40 08 09 10 11 12 08 09 10 11 12 Adjusted EBITDA ($ MM) Distributions Declared ($ per unit) 150 125 100 75 50 25 2.10 1.75 1.40 1.05 .70 .35 08 09 10 11 12 08 09 10 11 12 3 Marcellus Highlights In 2012, we acquired a significant position in the Marcellus Shale. We continue to grow our gathering and com- pression services to meet Antero’s aggres- sive development plan. 20 Year Gathering and compression services contract 100% Gathering system volume growth in 2012 500 MMcf/d Expected gathering system capacity in 2013 60+ Additional Marcellus Shale wells to be connected in 2013 4 Crestwood acquired a foothold in the premier Marcellus Shale rich gas play in 2012 Antero Resources’ gathering assets in the Marcellus Shale were an ideal addition to the Crestwood portfolio that diversified our business and increased cash flow stability. The initial acquisition by Crestwood Marcellus Midstream LLC (CMM) for $382 million in March 2012 gave us access to increasing volumes and a significant pipeline of organic growth projects and bolt- on acquisition opportunities. We have a 20-year, 100% fixed-fee contract to provide gathering and compression services for a successful producer executing an aggressive development plan. The $95 million bolt-on acquisition of Enerven compression assets followed, extending our contract services to Antero. Production volumes in 2012 exceeded projections, with throughput increasing from approximately 200 MMcf/d in early 2012 to approximately 400 MMcf/d at year- end. Today, our Marcellus assets account for approximately 40% of our gathering volumes. To acquire Antero’s gas gathering assets, we formed CMM, a joint venture company between Crestwood Holdings (65%) and Crestwood (35%). This structure allowed us to get in on the ground floor of a high-growth gathering business. At closing, our assets included 34 miles of low pressure pipelines gathering approximately 230 MMcf/d from 63 existing Marcellus Shale wells. CMM also entered into a 20-year gas gathering and compression agreement covering 136,000 acres of production dedication in two West Virginia counties. The contract with Antero includes substantial minimum volume guarantees through 2018 and a right-of-first-offer to acquire additional gathering and compression services from Antero on acreage adjacent to the existing dedication. Due to outstanding volume growth and a significant backlog of organic and bolt-on opportunities in the Marcellus region, Crestwood acquired Crestwood Holdings’ 65% interest in CMM for $258 million in January 2013 in our first “drop-down” transaction. Crestwood Holdings agreed to take 50% of the purchase price in CMLP equity to ensure that we maintain a conservative balance sheet. This transaction also helps Crestwood Holdings prepare for future joint venture and drop-down opportunities when appropriate acquisition and greenfield development prospects arise. We expect our Marcellus gathering volumes to increase approximately 50% in 2013 to an average of 460 MMcf/d from an average of 302 MMcf/d in 2012. Additionally, compression services, a new midstream fixed fee service will account for approximately 27% of total Marcellus revenues in 2013. To accommodate Antero’s drilling program and resulting volume growth, we expect to connect more than 60 new Marcellus Shale wells, build approximately 18 miles of pipelines and laterals and add 120 MMcf/d of new compression capacity that will be expandable to 240 MMcf/d in 2014 for future volume growth. In addition to our development opportunities with Antero in the rich gas area, we are currently building a dry gas gathering system in the Marcellus Shale for Mountaineer Keystone, an indirect affiliate of our general partner First Reserve. While the initial gathering system will allow Mountaineer Keystone to assess their acreage in 2013, we expect that higher natural gas prices in late 2013 and 2014 will support additional producer development in this area allowing us to move forward with our previously announced Tygart Valley pipeline. 5 Gas Control At a fully automated control station, Cody Stemkowski, Plant Operator at the Corvette Processing facility, continuously monitors natural gas as it is being processed. Cody can also adjust operations at the nearby Cowtown processing facility and monitor gas flow throughout the 500 mile Cowtown gathering system. Project Planning From design to final installation, Crestwood employees work together to ensure projects stay on track to meet customer needs. Matt Montgomery, Facilities Engineer, Robbie McDonough, Director of Land and Contracts, Dana DeLancy, Supply Chain Administration and George Grau, Vice President of Central Region Operations review the construction status of a gathering pipeline project. Continuous Safety Practices With safety as our number one priority, Crestwood employees conduct safety brief- ings at each shift change to mitigate risks to plant and pipeline personnel. Barnett Shale region maintenance technicians and mechanics Jose Saucedo, David Hinch and Buzz Berry review planned work activities with Miranda Jones, Vice President of Environment, Safety and Regulatory. Operational Efficiency Andy Malcolm, Instrumentation Technician, checks electrical switchgear to ensure efficient and reliable operations while natural gas flows through the Alliance Station. Located in the Dallas/Fort Worth metroplex, the compression and treating facility utilizes low emission electrical compression equip- ment and can treat up to 300 MMcf/d for the removal of CO2 from the natural gas stream. 6 To be a leader in midstream services, Crestwood is focused on building a vibrant organization and reliable asset base to provide best in class customer services in a safe and environmentally responsible way Our organization is growing with talented employees that have the skills, mindset and drive to create and run a successful midstream business in today’s competitive marketplace. Our unique organizational model has been developed through years of midstream experience by our management team. Through the integration of assets and personnel from numerous acquisitions in recent years, the Crestwood workforce is concentrated in the core midstream disciplines required to efficiently manage our operations, while human resources, information technology and other support functions are outsourced. As our strategies have changed and industry challenges have increased, we are investing in new areas such as operations management, engineering and project management, environmental, safety and regulatory compliance, business development and finance to expand our organization and meet the growing needs of our customers. This model enhances our ability to compete cost-effectively in the midstream sector and differentiates Crestwood from our competitors. Crestwood is investing heavily in the talent, systems and processes to create a great midstream organization. Our assets are designed and our organization is committed to being a leader in midstream services. With a focus on operational reliability through close monitoring of systems and plants, continuous improvement of safety practices, project planning and execution and continual enhancements to achieve operational efficiency we are establishing the right performance based employee culture. At Crestwood, we stress the importance of accountability, teamwork and communication as our guiding principles to promote customer service, employee safety and environmental stewardship. The Crestwood operating organization is a combination of original Barnett Shale employees supplemented by the integration of additional employees from each of our acquisitions in recent years. As we expanded into the Marcellus Shale region and developed a new business development function in 2012, these strategies caused Crestwood to expand its leadership, operations, accounting and support capabilities as well as the front line employees that are meeting the daily challenges of the new assets and business opportunities. Our shared services organizational model allows each of our operating regions to rely on centralized support from a team of experienced professionals located in Houston and Fort Worth, Texas. With a commitment to building the organization to match the assets, Crestwood is on the way to becoming a leader in midstream services. 7 We are Crestwood We are focused on safety and customer service, the values that will ultimately make Crestwood a successful and sustainable midstream business. We have blended our veteran executive management team with over 125 years of midstream experience, with the coming generation of resourceful, self-reliant young professionals. We are building an organization that recognizes the importance of balancing fresh ideas and proven experience necessary to execute our strategy. We understand that we must earn the business of our customers as we expand our assets and develop projects. With every employee having an ownership stake in the success of Crestwood, we are all committed to building value for our unitholders and becoming an industry leader in midstream services. 8 Ben Hansen Project Director Deidra Patterson Director, Financial Reporting Ben Evans Plant Manager, Barnett South Explanatory Note This Current Report on Form 8-K filed with the Securities and Exchange Commission (“SEC”) on March 18, 2013, is provided here as an update to the Crestwood Midstream Partners LP Annual Report on Form 10-K for the year ended December 31, 2012. On January 8, 2013, we acquired the remaining membership interests in Crestwood Marcellus Midstream LLC (“CMM”), which we formed as a joint venture on February 23, 2012 with Crestwood Holdings LLC. As a result, our historical financial information was required to be retrospectively adjusted to reflect the change in reporting entity and the consolidation of CMM. Accordingly, the following Current Report provides financial information that encompasses all of assets that Crestwood operated during 2012. To access our Annual Report on Form 10-K for the year ended December 31, 2012 or any other of our filings with the SEC, please visit our website at www.crestwoodlp.com or go to www.sec.gov. UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported): March 18, 2013 Crestwood Midstream Partners LP (Exact name of registrant as specified in its charter) Commission file number: Delaware (State or other jurisdiction of incorporation or organization) 001-33631 (Commission File Number) 700 Louisiana Street, Suite 2060 Houston, Texas (Address of principal executive offices) (832) 519-2200 (Registrant’s telephone number, including area code) 56-2639586 (I.R.S. Employer Identification No.) 77002 (Zip Code) Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions: ‘ Written communication pursuant to Rule 425 under the Securities Act (17 CFR 230.425) ‘ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) ‘ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) ‘ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) Item 8.01. Other Events On January 8, 2013, Crestwood Midstream Partners LP (the “Partnership”) filed a Current Report on Form 8-K to report is acquisition of a 65% limited liability company membership interest in Crestwood Marcellus Midstream LLC (“CMM”) from Crestwood Marcellus Holdings LLC (“Marcellus Holdings”), Crestwood Gas Services GP LLC, the general partner of the Partnership (the “General Partner”), Crestwood Holdings LLC (“Crestwood Holdings”), and Crestwood Gas Services Holdings LLC (“Gas Services Holdings”), collectively the “Contributing Parties.” Because the Partnership now owns 100% of CMM and has the ability to control CMM’s operating and financial decisions and policies, and because the limited liability company membership interest has been acquired from the Contributing Parties, applicable accounting standards required the acquisition of the interest to be accounted for as a reorganization of entities under common control. As a result, the Partnership’s historical financial information was retrospectively adjusted to reflect the change in reporting entity and the consolidation of CMM. Accordingly, the Partnership has updated certain information included in its Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 Annual Report”) filed with the Securities and Exchange Commission (“SEC”) on February 28, 2013 as follows: • • • • 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; and Item 8. Financial Statements and Supplementary Data. The Partnership has filed the updated information listed above as Exhibit 99.1 to this Current Report on Form 8-K (“Report”) which is incorporated herein by reference. Except with respect to the retrospective adjustment described above, the information included in this Report has not been updated to reflect events subsequent to the filing of the 2012 Annual Report. This Report should be read in conjunction with the portions of the 2012 Annual Report that have not be retrospectively adjusted herein, as well as in conjunction with the Partnership’s other filings with the SEC filed subsequent to the 2012 Annual Report. The historical financial statements of the acquired entity referenced in the Current Report on Form 8-K filed with the SEC on January 8, 2013 were filed with the Partnership’s 2012 Annual Report filed with the SEC on February 28, 2013. The supplemental consolidated financial statements in Item 8 of this Report serve to meet the requirement of the pro-forma financial information referenced in the Current Report on Form 8-K filed with the SEC on January 8, 2013. Item 9.01 Financial Statements and Exhibits (d) Exhibits. Exhibit Number 23.1 99.1 Consent of Independent Registered Public Accounting Firm Deloitte & Touche LLP Financial Information Description 2 SIGNATURES Pursuant to the requirements 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. CRESTWOOD MIDSTREAM PARTNERS LP By: CRESTWOOD GAS SERVICES GP LLC, its general partner By: /s/ Steven M. Dougherty Steven M. Dougherty Senior Vice President, Interim Chief Financial Officer and Chief Accounting Officer Dated: March 18, 2013 3 CRESTWOOD MIDSTREAM PARTNERS LP EXHIBIT INDEX Each exhibit identified below is filed as part of this report. Exhibit Number 23.1 99.1 Consent of Independent Registered Public Accounting Firm Deloitte & Touche LLP Financial Information Description 4 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in Registration Statement No. 333-171735 on Form S-3 and Registration Statement Nos. 333-145326 and 333-162928 on Forms S-8 of our report dated March 18, 2013 (which report expresses an unqualified opinion and includes an explanatory paragraph concerning the retroactive effect of the common control acquisition of Crestwood Marcellus Midstream LLC), relating to the supplemental consolidated financial statements of Crestwood Midstream Partners LP and subsidiaries, appearing in this Current Report on Form 8-K of Crestwood Midstream Partners LP. Exhibit 23.1 /s/ DELOITTE & TOUCHE LLP Houston, Texas March 18, 2013 [THIS PAGE INTENTIONALLY LEFT BLANK] Exhibit 99.1 On February 23, 2012, we and Crestwood Holdings Partners, LLC and its affiliates (Crestwood Holdings) formed the Crestwood Marcellus Midstream LLC (CMM) joint venture. We contributed approximately $131 million for a 35% membership interest and Crestwood Holdings contributed approximately $244 million for a 65% membership interest. On January 8, 2013, we acquired Crestwood Holdings 65% membership interest in CMM. Because we now own 100% of CMM and have the ability to control CMM’s operating and financial decisions and policies and because the limited liability company membership interest has been acquired from related parties, applicable accounting standards required the acquisition of the interest to be accounted for as a reorganization of entities under common control. Accordingly, we have consolidated CMM and have retrospectively adjusted certain items included in our Annual Report on Form 10-K for the year ended December 31, 2012 filed with the Securities and Exchange Commission on February 28, 2013, as further noted below to reflect the change in reporting entity. Selected Financial Data Item 6. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Financial Statements and Supplementary Data Page 2 4 19 20 Below is a list of terms that are common to our industry and used throughout this document: “/d” means per day “Bbl(s)” means barrel or barrels “Btu” means British Thermal units, a measure of heating value “hp” means horsepower “Mcf” means thousand cubic feet “MMBtu” means million Btu “MMcf” means million cubic feet “NGL(s)” means natural gas liquids “Oil” includes crude oil and condensate When we refer to “we,” “us,” “our,” or “CMLP” we are describing Crestwood Midstream Partners LP and its consolidated subsidiaries. Item 6. Selected Financial Data The following selected historical financial data as of December 31, 2012 to 2008 and for the years ended December 31, 2012 to 2008 is derived from the audited consolidated financial statements for CMLP and its subsidiaries. The selected historical financial data is not necessarily indicative of results to be expected in future periods. On February 23, 2012, we and Crestwood Holdings formed the CMM joint venture. We contributed approximately $131 million for a 35% membership interest and Crestwood Holdings contributed approximately $244 million for a 65% membership interest. On January 8, 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM and as a result have the ability to control CMM’s operating and financial decisions and policies. This transaction was accounted for as a reorganization of entities under common control and accordingly, we have consolidated CMM and have retrospectively adjusted our historical financial statements as of and for the year ended December 31, 2012 to reflect the change in reporting entity. The selected financial data should be read together with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data included in this Report. Statement of Income Data: Operating revenues Operating income Income before income taxes Net income from continuing operations Loss from discontinued operations Net income Performance Measures: Diluted income per unit: From continuing operations per limited partner unit Net income from continuing operations per limited partner unit Distributions declared per limited partner unit (2) Volumes gathered (MMcf) Volumes processed (MMcf) Non-GAAP Performance Measures: EBITDA (3) Adjusted EBITDA (4) Balance Sheet Data: Property, plant and equipment, net Total assets Long-term debt Other long-term obligations (5) Partners’ capital Year Ended December 31, 2012 2011 2010 (1) 2009 2008 $ 239,463 75,860 40,095 38,889 — 38,889 $ 205,820 73,871 46,254 45,003 — 45,003 $113,590 47,872 34,322 34,872 — 34,872 $ 95,881 43,408 34,890 34,491 (1,992) 32,499 $ 76,084 37,151 28,725 28,472 (2,330) 26,142 $ $ $ 0.37 0.37 2.02 $ $ $ 1.00 1.00 1.87 $ $ $ 1.03 1.03 1.66 $ $ $ 1.25 1.18 1.52 $ $ $ 1.03 0.95 1.39 301,061 63,264 208,146 52,613 125,317 46,660 93,955 54,386 70,617 56,225 $ 127,768 132,465 $ 107,683 109,962 $ 70,231 76,549 $ 64,238 64,238 $ 50,293 50,293 $ 939,846 1,610,469 685,161 17,185 859,609 $ 746,045 $531,371 570,627 1,026,892 283,504 512,500 15,474 9,877 258,753 455,623 $482,497 487,624 125,400 62,162 284,837 $441,863 502,606 174,900 123,928 115,208 (1) In January 2010, we acquired from Quicksilver Resources Inc. (Quicksilver) certain midstream assets consisting of a gathering system and a compression facility, an amine treating facility and a dehydration facility in northern Tarrant and southern Denton Counties, Texas. We refer to these assets collectively as the “Alliance Assets” and the acquisition as the “Alliance Acquisition.” Due to Quicksilver’s control of CMLP 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, CMLP 2 was required to revise its financial statements to include the financial results and operations of the Alliance Assets. As such, the selected financial data gives retroactive effect to the Alliance Acquisition as if CMLP owned the Alliance Assets since August 8, 2008, the date on which Quicksilver acquired the Alliance Assets. (2) Reported amounts include the fourth quarter distribution, which was paid in the first quarter of the subsequent year. (3) Defined as net income plus interest expense, income tax provision, and depreciation, amortization and accretion expense (EBITDA). Additional information regarding EBITDA, including a reconciliation of EBITDA to net income as determined in accordance with GAAP, is included in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. (4) Defined as EBITDA adjusted for the impact of certain significant items, such as third party costs incurred related to potential and completed acquisitions and other transactions identified in a specific reporting period. Additional information regarding Adjusted EBITDA, including a reconciliation of Adjusted EBITDA to net income as determined in accordance with GAAP, is included in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. (5) Other long-term obligations include our capital leases and asset retirement obligations. 3 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Overview Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. Our MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. On February 23, 2012, we and Crestwood Holdings Partners, LLC and its affiliates’ (Crestwood Holdings) formed the Crestwood Marcellus Midstream LLC (CMM) joint venture. We contributed approximately $131 million for a 35% membership interest and Crestwood Holdings contributed approximately $244 million for a 65% membership interest. On January 8, 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM and as a result have the ability to control CMM’s operating and financial decisions and policies. This transaction was accounted for as a reorganization of entities under common control and accordingly, we have consolidated CMM and have retrospectively adjusted our historical financial statements as of and for the year ended December 31, 2012 to reflect the change in reporting entity. Listed below is a general outline of our MD&A: • Business and Performance Metrics • Current Year Highlights • Results of Operations • Liquidity and Capital Resources • Off Balance Sheet Arrangements and Contractual Obligations • Critical Accounting Estimates Business and Performance Metrics We are a growth-oriented midstream master limited partnership which owns and operates predominately fee-based gathering, processing, treating and compression assets servicing natural gas producers in the Barnett Shale in north Texas, the Fayetteville Shale in northwestern Arkansas, the Granite Wash in the Texas Panhandle, the Marcellus Shale in northern West Virginia, the Avalon Shale/Bone Spring in southeastern New Mexico, and the Haynesville/Bossier Shale in western Louisiana. We provide midstream services to various producers that focus on developing unconventional resources across the United States. Our largest producer is Quicksilver Resources Inc. (Quicksilver). For the years ended December 31, 2012, 2011, and 2010, Quicksilver’s production volumes accounted for 43%, 59% and 86% of our total revenues. We also gather certain natural gas volumes that Quicksilver purchases from Eni SpA, which comprised 4%, 5% and 7% of our total revenues for the years ended December 31, 2012, 2011 and 2010. We conduct all of our operations in the midstream sector in eight operating segments, four of which are reportable. Our operating segments reflect how we manage our operations and are generally reflective of the geographic areas in which we operate. Our reportable segments consist of Barnett, Fayetteville, Granite Wash and Marcellus. Our operating segments are engaged in gathering, processing, treating, compression, transportation and sales of natural gas and delivery of NGLs in the United States. The results of our operations are significantly influenced by the volumes of natural gas gathered and processed through our systems. We gather, process, treat, compress, transport and sell natural gas pursuant to fixed-fee and percent-of-proceeds contracts. Under our fixed-fee contracts, we do not take title to the natural gas or associated NGLs. For the year ended December 31, 2012, approximately 98% of our gross margin, which we define as total revenue less product purchases, is derived from fixed-fee service contracts, which minimizes our commodity price exposure and provides us with less volatile operating performance and cash flows. Under our 4 percent-of-proceeds contracts, we take title to the residue gas, NGLs and condensate and remit a portion of the sale proceeds to the producer based on prevailing commodity prices. For the year ended December 31, 2012, revenues from percent-of-proceeds contracts accounted for approximately 2% of our gross margin. Although we do not have significant direct commodity price exposure, lower natural gas prices could have a potential negative impact on the pace of drilling in dry gas areas – such as areas in the Barnett Shale (gathered by the Alliance and Lake Arlington Systems), the Fayetteville Systems and the Sabine System (part of the Haynesville/Bossier Shale). We operate five systems located in basins that include NGL rich gas shale plays: (i) the Cowtown System; (ii) the Granite Wash System; (iii) the Las Animas Systems; and (iv) two systems in the Marcellus segment. For the year ended December 31, 2012, our systems located in NGL rich gas basins contributed approximately 61% of our total revenues and 51% of total gathering volumes. A prolonged decrease in the commodity price environment could result in our customers reducing their production volumes which would result in a decrease in our revenues. 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. Volumes — We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. We routinely monitor producer activity in the areas we serve to identify new supply opportunities. Our ability to achieve these objectives is impacted by: • • • the level of successful drilling and production activity in areas where our systems are located; our ability to compete with other midstream companies for production volumes; and our pursuit of new acquisition opportunities. Operations and Maintenance Expenses — We consider operations and maintenance expenses in evaluating the performance of our operations. These expenses are comprised primarily of labor, parts and materials, insurance, taxes other than income taxes, repair and maintenance costs, utilities and contract services. Our ability to manage operations and maintenance expenses has a significant impact on our profitability and ability to pay distributions. EBITDA and Adjusted EBITDA — We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company’s operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. EBITDA and Adjusted EBITDA are not measures calculated in accordance with accounting principles generally accepted in the United States of America (GAAP), as they do not include deductions for items such as depreciation, amortization and accretion, interest and income taxes, which are necessary to maintain our business. In addition, Adjusted EBITDA considers the impact of certain significant items, such as third party costs incurred related to potential and completed acquisitions and other transactions identified in a specific reporting period. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies. See our reconciliation of Net Income to EBITDA and Adjusted EBITDA in Results of Operations below. Current Year Highlights Below is a discussion of events that highlight our core business and financing activities. 5 Operational and Industry Highlights Shale gas production in the United States has grown rapidly in recent years as the natural gas industry has improved drilling and extraction methods while increasing exploration efforts. The United States has a wide distribution of shale formations containing vast resources of natural gas, NGLs and oil. Led by the rapid development of the Barnett Shale in Texas, shale gas activity has expanded into other areas such as the Marcellus, Fayetteville and Haynesville/Bossier shale plays. Growth through Diversification — Our operating results reflect our ability to diversify our shale play portfolio and increase volumes not only through our base business located in the Barnett Shale, but also through strategic acquisitions in a number of attractive shale plays in the United States. We believe that or experience and market position will allow us to realize significant ongoing growth opportunities by developing new greenfield projects in NGL and oil plays in areas with limited or constrained infrastructure which offer attractive returns on investment and seeking bolt-on acquisitions that provide operating synergies and allow for the development of our business in rich gas infrastructure plays, similar to our acquisitions from Antero Resources Appalachian Corporation (Antero), Devon Energy Corporation (Devon) and E. Marcellus Asset Company, LLC (EMAC) . Our acquisition strategy includes diversifying and extending our geographic, customer and business profile and developing organic growth opportunities along the midstream value chain. Our consolidated systems gathered 897 MMcf/d for the year ended December 31, 2012 which is an increase of 57% from 2011 and 162% from 2010. Additionally, our processed volumes were 173 MMcf/d in 2012, an increase of 20% from 2011 and 35% from 2010. The increase in volumes resulted in a 16% increase in our overall revenues from 2011 and 111% from 2010. Distribution Growth — For the year ended December 31, 2012, we either declared or paid distributions of $2.02 per limited partner unit, which represents an 8% increase over the distributions related to 2011 and a 22% increase over the distributions related to 2010. Acquisitions Antero Acquisition On February 24, 2012, we announced the execution of an Asset Purchase Agreement related to the acquisition of gathering assets owned by Antero in the Marcellus Shale located in Harrison and Doddridge Counties, West Virginia (Antero Acquisition), and, at closing, the planned execution of a 20 year Gas Gathering and Compression Agreement (GGA) with Antero. On March 26, 2012, CMM completed the Antero Acquisition for approximately $380 million. The assets acquired by CMM consisted of a 33 mile low pressure gathering system at the time of acquisition. The gathering pipelines deliver Antero’s Marcellus Shale production to various regional pipeline systems including Columbia, Dominion and Equitrans and Mark West Energy Partners’ Sherwood Gas Processing Plant. Additionally, CMM entered into a 20 year, fixed-fee, Gas Gathering and Compression Agreement (GGA) with Antero, which provided for an area of dedication at the time of acquisition of approximately 127,000 gross acres, or 104,000 net acres, largely located in the rich gas corridor of the southwestern core of the Marcellus Shale play. As part of the GGA, Antero committed to delivery of minimum annual volumes to CMM for a seven year period from January 1, 2012 to January 1, 2019, ranging from an average of 300 MMcf/d in 2012 to an average of 450 MMcf/d in 2018. During the period ended December 31, 2012, Antero delivered less than the minimum annual throughput volumes and at December 31, 2012, we recorded a receivable and deferred revenue of approximately $2.6 million due to Antero’s ability under the GGA to earn the amount associated with the volume deficiency during 2013. Antero may earn additional payments of up to $40 million based upon average annual production levels achieved during 2012, 2013 and 2014. During 2012, Antero did not meet the annual production level to earn additional payments. 6 Devon Acquisition On August 24, 2012, we completed the acquisition of certain gathering and processing assets in the NGL rich gas region of the Barnett Shale from Devon for approximately $87 million (the Devon Acquisition). The assets acquired consist of a 74 mile low pressure natural gas gathering system, a 100 MMcf/d cryogenic processing facility and 23,100 hp of compression equipment, and are located in Johnson County, Texas near our Cowtown gathering system. Additionally, we entered into a 20 year, fixed-fee gathering, processing and compression agreement with Devon, under which we will gather and process Devon’s natural gas production from a 20,500 acre dedication. Natural gas production gathered and processed under the agreement was approximately 96 MMcf/d as of December 31, 2012. Due to the NGL rich gas quality of the natural gas production in this region of the Barnett Shale, Devon maintained an active drilling and development plan for the Johnson County area in 2012 and expects to continue to further develop the dedicated properties in 2013. EMAC Acquisition On December 28, 2012, CMM acquired all of the membership interests in E. Marcellus Asset Company, LLC (EMAC) for approximately $95 million, which was financed through CMM’s $200 million credit facility. EMAC’s assets consist of four compression and dehydration stations located on CMM’s gathering systems in Harrison County, West Virginia. These assets provide compression and dehydration services to Antero under a compression services agreement through 2018. Antero has the option to renew the agreement for an additional five years upon expiration of the original agreement. Financing Activities Equity Offerings During 2012, we completed public offerings of 8,100,000 common units, representing limited partner interests, providing net proceeds of approximately $218 million. The net proceeds from these offerings were used to fund the amounts paid for the Devon Acquisition and to reduce indebtedness under our Credit Facility. Our General Partner also made additional capital contributions during 2012 of approximately $6 million to maintain its 2% general partner interest. For additional information regarding our equity offerings, see Item 8. Financial Statements and Supplementary Data, Note 14. Partners’ Capital. Credit Facility On March 26, 2012, in conjunction with the acquisition of Antero’s gathering system assets, CMM entered into a credit agreement with certain lenders. The five year term credit agreement allows for revolving loans, letters of credit and swingline loans in an aggregate principal amount of up to $200 million. The CMM credit facility is secured by substantially all of its assets. Senior Notes On November 14, 2012, we issued an additional $150 million aggregate principal amount of 7.75% Senior Notes in a private placement offering. These notes were issued as additional notes under the indenture dated April 1, 2011 among us, Crestwood Midstream Finance Corporation, the guarantors named therein, and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which we previously issued our $200 million aggregate principal amount of 7.75% Senior Notes in April 2011. The net proceeds from the offering were used to reduce our indebtedness under our CMLP credit facility. 7 Results of Operations The following table summarizes our results of operations for each of the three years ended December 31, 2012 (In thousands): Total operating revenues Product purchases Operations and maintenance expense General and administrative expense Depreciation, amortization and accretion Gain from exchange of property, plant and equipment Operating income Interest and debt expense Income tax expense (benefit) Net income Add: Interest and debt expense Income tax expense Depreciation, amortization and accretion expense EBITDA Expenses associated with significant items Gain from exchange of property, plant and equipment Adjusted EBITDA Year Ended December 31, 2012 2011 2010 $239,463 39,005 43,108 29,582 51,908 — 75,860 35,765 1,206 $205,820 38,787 36,303 24,153 33,812 1,106 73,871 27,617 1,251 $113,590 — 25,702 17,657 22,359 — 47,872 13,550 (550) $ 38,889 $ 45,003 $ 34,872 35,765 1,206 51,908 27,617 1,251 33,812 13,550 (550) 22,359 $127,768 4,697 — $107,683 3,385 (1,106) $ 70,231 6,318 — $132,465 $109,962 $ 76,549 EBITDA in the table above includes operating results from our Barnett, Fayetteville, Granite Wash and Marcellus segments and other operations, general and administrative expenses, and the gain from exchange of property, plant and equipment. The following table summarizes the results of our Barnett, Fayetteville, Granite Wash and Marcellus segments and other operations (In thousands): Gathering revenues Processing revenues Product sales Total operating revenues Product purchases Operations and maintenance expense Year Ended December 31, 2012 Barnett Fayetteville Granite Wash Marcellus Other Total $ 98,889 34,003 141 $133,033 125 26,881 $26,986 — 512 $27,498 523 8,537 $ 1,434 130 38,992 $40,556 35,695 2,250 $25,502 $10,202 $163,013 34,133 — 42,317 2,672 — — $25,502 $12,874 $239,463 39,005 2,662 43,108 2,949 — 2,491 EBITDA $106,027 $18,438 $ 2,611 $23,011 $ 7,263 Gathering volumes (in MMcf) Processing volumes (in MMcf) 158,087 56,844 31,617 — 6,440 6,420 83,147 — 21,770 — 301,061 63,264 8 Gathering revenues Processing revenues Product sales Total operating revenues Product purchases Operations and maintenance expense Year Ended December 31, 2011 Barnett Fayetteville Granite Wash Marcellus Other Total $108,705 31,379 — $140,084 — 25,147 $19,421 — 1,379 $20,800 1,302 8,992 $ 346 133 37,734 $38,213 33,245 1,499 $ — $2,483 $130,955 31,512 — 43,353 4,240 — — $ — $6,723 $205,820 38,787 4,240 36,303 665 — — EBITDA $114,937 $10,506 $ 3,469 — $1,818 Gathering volumes (in MMcf) Processing volumes (in MMcf) 172,838 48,112 23,421 — 4,555 4,501 — — 7,332 — 208,146 52,613 Gathering revenues Processing revenues Total operating revenues Operations and maintenance expense EBITDA Gathering volumes (in MMcf) Processing volumes (in MMcf) Year Ended December 31, 2010 Barnett Fayetteville Granite Wash Marcellus Other Total $ 83,394 30,196 $113,590 25,702 $ 87,888 125,317 46,660 $ — — $ — — — — — $ — — $ — — $ — $ — $ 83,394 30,196 — — $ — $ — $113,590 25,702 — — — — — — — — — — 125,317 46,660 — EBITDA and Adjusted EBITDA — EBITDA for the year ended December 31, 2012 was approximately $128 million, an increase of approximately $20 million from 2011 and approximately $58 million from 2010. In the same manner, Adjusted EBITDA for the year ended December 31, 2012 was approximately $132 million, an increase of approximately $23 million from 2011 and approximately $56 million from 2010. Adjusted EBITDA considers expenses for evaluating certain transaction opportunities, which was approximately $4 million, $3 million and $6 million for the years ended December 31, 2012, 2011 and 2010. Adjusted EBITDA also considers the impact of other significant items, including but not limited to items such as operational costs, which were less than $1 million at December 31, 2012 and the gain on the exchange of property, plant and equipment, which was approximately $1 million at December 31, 2011. Below is a discussion of the factors that impacted EBITDA by segment for the year ended December 31, 2012 compared to 2011 and the year ended December 31, 2011 compared to 2010: Barnett: During the year ended December 31, 2012, our Barnett segment’s EBITDA was approximately $9 million lower than in 2011, primarily due to lower gathering revenues. During 2011, gathering revenues in our Barnett segment were higher compared to 2010, which increased our segment EBITDA by approximately $27 million. Revenues and Volumes — Revenues in our Barnett segment decreased by approximately $7 million during the year ended December 31, 2012 compared to 2011, primarily due to lower dry gas gathering volumes. The decrease in gathering volumes primarily related to reduced production from existing wells and well shut-ins at our Alliance and Lake Arlington gathering systems. These decreases in volumes were partially offset by producers connecting 64 new wells during the year ended December 31, 2012. 9 Also, partially offsetting the decline in gathering revenues and volumes during 2012 was an increase in gathering and processing revenues due to the Devon Acquisition, which was completed on August 24, 2012. During the year ended December 31, 2012, the acquired assets generated approximately $7 million of gathering and processing revenues for our Barnett segment. In addition to the items discussed above, our revenues were also unfavorably impacted by a compressor building fire that occurred on September 6, 2012 at our Corvette processing plant, which reduced revenues by approximately $0.5 million. Additional impacts to the Barnett segment’s EBITDA for the year ended December 31, 2012, as a result of the compressor building fire are further discussed below. During 2011, we experienced an increase in gathering volumes in our Barnett segment compared to 2010, primarily from the operations of our Alliance System. The increase in revenue of approximately $26 million primarily related to the Alliance System volumes that were the result of Quicksilver’s drilling program pursuant to a joint development agreement with Eni SpA, which resulted in an increase of approximately 75 MMcf/d in gathered volumes and approximately $16 million in revenues. Operations and Maintenance Expense — Operations and maintenance expenses in our Barnett segment increased by approximately $2 million or 7% for the year ended December 31, 2012 when compared to 2011, while remaining relatively flat from 2011 compared to 2010. The increase in operations and maintenance expenses was primarily due to (i) the Devon Acquisition; (ii) approximately $0.2 million of costs related to a condensate spill at our Corvette facility; and (iii) a compressor building fire at our Corvette processing plant. As a result of the building fire at our Corvette processing plant, we impaired assets of approximately $1.6 million, incurred repair costs of approximately $2.2 million, and recorded amounts recoverable from our insurers of approximately $3.6 million, all of which resulted in a net impact to our operations and maintenance expenses of approximately $0.2 million. Fayetteville: We acquired certain midstream assets in the Fayetteville Shale during 2011, which contributed 64 MMcf/d of gathering volumes and approximately $21 million in revenues in our Fayetteville segment. Our Fayetteville segment EBITDA increased approximately $8 million during the year ended December 31, 2012 compared to 2011, primarily due to higher revenues and volumes. Revenues and Volumes — During the year ended December 31, 2012, BHP Billiton Petroleum, Plc. (BHP) connected six new wells on our Twin Groves System, contributing to an increase in revenues and volumes in our Fayetteville segment. Additionally, we recognized twelve months of revenues in 2012 versus nine months during 2011 due to the acquisition of our operations in Fayetteville on April 1, 2011. Operations and Maintenance Expense — Operations and maintenance expenses in our Fayetteville segment during the year ended December 31, 2012 were relatively flat compared to 2011. Granite Wash: During 2011, we acquired certain midstream assets in the Granite Wash, which contributed 13 MMcf/d and approximately $38 million in revenues primarily related to product sales under percent-of-proceeds contracts. For the year ended December 31, 2012, our Granite Wash segment’s EBITDA was approximately $0.8 million lower than in 2011 primarily due to lower product sales margin and higher operations and maintenance expenses. Revenues/Margin and Volumes — For the year ended December 31, 2012, Granite Wash’s EBITDA decreased compared to 2011, due to lower margins earned on our percent-of-proceeds contracts, which primarily resulted from lower NGL and natural gas prices experienced during the year ended December 31, 2012 coupled with relatively consistent costs per volume. Partially offsetting this decrease in product sales margin was higher 10 gathering revenues due to new wells connected by Sabine Oil and Gas LLC (Sabine) during the year ended December 31, 2012. In addition, we recognized twelve months of revenues in 2012 versus nine months during 2011 due to the acquisition of operations in Granite Wash on April 1, 2011. Operations and Maintenance Expense — For the year ended December 31, 2012 compared to 2011, operations and maintenance expenses were higher due to the increase in volumes resulting from the new wells connected by Sabine. Marcellus: On February 23, 2012, we and Crestwood Holdings formed the CMM joint venture. On March 26, 2012, CMM completed the Antero Acquisition, which contributed 210 MMcf/d of gathering volumes at the time of acquisition and 302 MMcf/d for the year ended December 31, 2012. Revenues from our Marcellus segment were approximately $26 million for the year ended December 31, 2012. On December 28, 2012, CMM completed the acquisition of EMAC whose assets consisted of four compression and dehydration stations located on CMM’s gathering systems in Harrison County, West Virginia. These assets provide compression and dehydration services to Antero under a compression services agreement through 2018. Other: Our other operations include our assets in the Haynesville/Bossier Shale (Sabine System) and our assets in the Avalon Shale/Bone Spring (Las Animas System). We acquired the Sabine and Las Animas Systems during 2011. These systems contributed 20 MMcf/d of gathering volumes and approximately $7 million in revenues during 2011. For the year ended December 31, 2012, our other operations’ EBITDA increased by approximately $5 million compared to 2011, primarily due to the operations of our Sabine System. Revenues and Volumes — The Sabine System had 50 MMcf/d in gathered volumes for the year ended December 31, 2012, which resulted in approximately $10 million in revenues for the year ended December 31, 2012. In addition, we recognized twelve months of revenues from our Sabine System in 2012 versus two months in 2011 due to the acquisition of operations in the Sabine System in November 2011. EBITDA related to our Las Animas System remained relatively unchanged for the year ended December 31, 2012 compared to 2011. Operations and Maintenance Expense — Operations and maintenance expenses increased during the year ended December 31, 2012, primarily due to our Sabine System acquired in November 2011. Below is a discussion of items impacting EBITDA that are not allocated to our segments. General and Administrative Expenses — During the year ended December 31, 2012, general and administrative expenses increased by approximately $5.4 million when compared 2011, primarily due to the acquisition of the Antero assets in March 2012. General and administrative expenses include costs related to legal and other consulting services to evaluate certain transaction opportunities and other non-recurring matters. We incurred approximately $4.7 million of these costs during 2012 as compared to $3.4 million in 2011. The increase in general and administrative expenses of $6.5 million for the year ended December 31, 2011 compared to 2010, was primarily due to the transition of our operations from Quicksilver as a result of Crestwood Holdings’ acquisition of its membership interest in us from Quicksilver. These costs included personnel, new administrative systems and the increased scope of business operations as a result of our acquisitions during 2011. Also impacting our general and administrative expenses for the year ended December 31, 2012 were increases in payroll and related benefit costs, which reflects the increased scope of our business operations compared to 2011. 11 Items not affecting EBITDA include the following: Depreciation, Amortization and Accretion Expense — We have experienced increases in our depreciation, amortization and accretion expense primarily due to assets acquired during 2012 and 2011. Interest and Debt Expense — Interest and debt expense increased for the year ended December 31, 2012 compared to 2011, primarily due to (i) higher outstanding balances on our CMLP credit facility; (ii) the $200 million CMM credit facility entered into in March 2012; (iii) the issuance of an additional $150 million of 7.75% Senior Notes in November 2012; and (iv) our Senior Notes issued in April 2011 being outstanding for the entire year of 2012 versus nine months during 2011. For a further discussion of our credit facilities and Senior Notes, see Item 8. Financial Statements and Supplementary Data, Note 5. Financial Instruments. The following table provides a summary of interest and debt expense (In thousands): Credit Facility Senior Notes Bridge Loan Capital lease interest Subordinated note Other debt-related costs Total cost Less capitalized interest Total interest and debt costs Year Ended December 31, 2012 2011 2010 $17,570 17,833 — 230 — 423 $12,971 12,166 2,500 179 — — 36,056 (291) 27,816 (199) $11,532 — — — 2,018 — 13,550 — $35,765 $27,617 $13,550 Liquidity and Capital Resources Our sources of liquidity include cash flows generated from operations, available borrowing capacity under our credit facilities, and issuances of additional debt and equity in the capital markets. We believe that our sources of liquidity will be sufficient to fund our short-term working capital requirements, capital expenditures and cash distributions for 2013. The amount of distributions to unitholders is determined by the board of directors of our General Partner on a quarterly basis. We regularly review opportunities for both acquisitions and greenfield growth projects that will enhance our financial performance. Since we distribute most of our available cash to our unitholders, we depend on a combination of borrowings under our credit facilities and debt or equity offerings to finance the majority of our long-term growth capital expenditures or acquisitions. Management continuously monitors our leverage position and our anticipated capital expenditures relative to our expected cash flows. We continue to evaluate funding alternatives, including additional borrowings and the issuance of debt or equity securities, to secure funds as needed or refinance outstanding debt balances with longer term notes. 12 Known Trends and Uncertainties Impacting Liquidity Our financial condition and results of operations, including our liquidity and profitability, can be significantly affected by the following: • Concentration of Gathering Revenues from Quicksilver: While we have reduced our dependency upon Quicksilver through the acquisition of additional midstream assets that have long term contracts with creditworthy producers such as BHP, Devon, Antero, British Petroleum, Plc. (BP), XTO Energy, a subsidiary of Exxon Mobil Corporation (XTO Energy) and Chesapeake Energy Corporation (Chesapeake), we remain dependent upon Quicksilver for a substantial percentage of our current business. For the years ended December 31, 2012, 2011, and 2010 Quicksilver’s production volumes accounted for 43%, 59% and 86% of our total revenues. We also gather certain natural gas volumes that Quicksilver purchases from Eni Spa, which comprised 4%, 5% and 7% of our total revenues for the years ended December 31, 2012, 2011, and 2010. The risk of revenue fluctuations in the near term is mitigated by the use of fixed-fee contracts for providing gathering, processing, treating and compression services; however, our revenues may be impacted by volume fluctuations. While our acquisitions reduce the concentration of risk associated with our dependency on one producer and one geographic area, we continue to regularly review opportunities for both acquisitions and greenfield growth projects in other producing basins and with other producers in the future. • Access to Capital Markets: The borrowings under our credit facilities were $334 million as of December 31, 2012 and based on our results through December 31, 2012, our remaining available capacity under the credit facilities was $226 million. While we anticipate that our current available borrowing capacity under our credit facilities is sufficient to fund our planned level of growth capital spending for 2013, additional debt and equity offerings may be necessary to fund additional acquisitions or other growth capital projects. During 2012, 2011 and 2010, we raised approximately $618 million, $500 million and $91 million through debt and equity offerings and increases to our credit facilities to fund acquisitions and growth capital projects. In January 2013, we borrowed $129 million under our CMLP credit facility to fund the acquisition of our additional membership interest in CMM. • Natural Gas Prices: Adding new volumes through our gathering systems is dependent on the drilling and completion activities of natural gas producers in our areas of operations. Although investment returns differ between natural gas basins, rich gas and dry gas reservoirs in certain natural gas basins and between various production companies, low natural gas prices may reduce the levels of drilling activity in areas around certain of our assets, particularly those that concentrate on gathering from dry gas reservoirs. We seek to mitigate this risk by diversifying into various geographical production basins with predominately rich gas natural gas reservoirs. We have observed that largely due to superior prices for crude oil and NGLs compared to natural gas, producers are shifting their drilling and development plans to focus on increasing production from rich gas basins or shale plays which offer better drilling economics as compared to production from dry gas basins. We have five systems located in basins that include NGL rich gas shale plays, (i) the Cowtown System; (ii) the Granite Wash System; (iii) the Las Animas Systems; and (iv) two systems in the Marcellus segment. For the year ended December 31, 2012, these rich gas systems accounted for approximately 61% of our total revenues. We will continue to focus on expanding our business activities and opportunities in rich gas basins or rich gas shale plays due to the current trend of increased drilling and producer activities in these areas. • Regulatory Requirements: Our operations and the operations of our customers are subject to complex and evolving federal, state, local and other laws and regulations. For example, on April 17, 2012, the United States Environmental Protection Agency issued a final rule establishing new emission limitations for certain oil and gas facilities. These rules establish emission standards for gas wells that are hydraulically fractured (or re-fractured). These rules also establish emissions standards for natural gas processing equipment, including compressors, controllers, storage tanks, and gas processing plants. 13 These or other federal or state initiatives relating to hydraulic fracturing or other environmental matters could impact the extent of our operations and/or give rise to or accelerate the need for additional capital projects. In addition, any further changes in laws or regulations, or delays in the issuance of required permits, may further impact the volumes on our systems. • Impact of Inflation and Interest Rates: Although inflation in the United States has been relatively low in recent years, the United States economy may experience a significant inflationary effect in the future. Although inflation would negatively impact the cost of our operations and cash flows through services provided to us, the majority of our gathering and processing agreements allow us to charge increased rates based on indices expected to track such inflationary trends. Interest rates have also remained low in recent years, as compared with historical averages. Should interest rates rise, our financing costs would increase accordingly. In addition, as with other yield-oriented securities, our unit price would also be negatively impacted by higher interest rates. Higher interest rates would increase the costs of issuing debt or equity necessary to finance potential future acquisitions. However, our competitors would face similar circumstances and we expect our cost of capital to remain competitive. Cash Flows The following table provides a summary of our cash flows by category (In thousands): Net cash provided by operating activities Net cash used in investing activities Net cash provided by financing activities Operating Activities Year Ended December 31, 2012 2011 2010 $ 102,065 (616,517) 513,766 $ 86,331 (456,535) 370,999 $ 48,003 (149,345) 100,598 Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 — During the year ended December 31, 2012, we generated cash flows from operations of $102 million compared to $86 million in 2011. This increase was primarily due to higher revenues as a result of our acquisitions of the Fayetteville and Sabine Systems during 2011 and the Antero and Devon Acquisitions during 2012. Those increases were partially offset by higher operations and maintenance expenses, higher general and administrative expenses due to our asset acquisitions during 2012 and 2011, higher payroll and benefits costs due an increase in employee headcount, and increased interest costs due to higher outstanding balances on our credit facilities and Senior Notes. Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 — During the year ended December 31, 2011, our operating cash flows increased approximately $38 million compared to 2010, primarily due to the acquisition of certain midstream assets in the Fayetteville Shale and Granite Wash and the acquisition of our Las Animas and Sabine Systems. In addition, we experienced improved performance in our Barnett operations during 2011. Also contributing to the increase in our operating cash flows during 2011 was an increase in accounts payable and accrued expenses related to our operations, ad valorem taxes and interest expense due to higher outstanding balances on our Credit Facility and the issuance of our Senior Notes in April 2011. Partially offsetting these items were higher receivables from our Fayetteville and Granite Wash operations. Investing Activities The midstream energy business is capital intensive, requiring significant investments for the acquisition or development of new facilities. We categorize our capital expenditures as either: • expansion capital expenditures, which are made to construct additional assets, expand and upgrade existing systems, or acquire additional assets; or 14 • maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets, extend their useful lives or comply with regulatory requirements. During 2013, we expect to spend between $120 million and $150 million on capital projects, of which approximately $10 million will relate to maintenance capital expenditures. We anticipate that our expansion capital expenditures in 2013 will expand our gathering systems through additional pipelines to connect to new wells, purchase additional compression equipment and generally increase the capacity of our systems in each of our operating segments, primarily in the Marcellus segment. We expect to fund our capital expenditures through additional capital market transactions, borrowings under our credit facilities and cash generated from operations. In January 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM for $258 million, which was funded through $129 million of borrowings under our CMLP credit facility and the issuance of $129 million of equity to Crestwood Holdings. We believe this acquisition will increase our potential for long-term organic growth opportunities in the Marcellus Shale region. Our cash flows from investing activities were impacted by the following significant items during the three years ended December 31, 2012, 2011 and 2010. Year Ended December 31, 2012: • The Antero Acquisition for approximately $380 million; • The Devon Acquisition for approximately $87 million; • The EMAC acquisition for approximately $95 million; and • Capital expenditures of approximately $53 million, including $4 million related to maintenance capital expenditures. Year Ended December 31, 2011: • Acquisition of the Fayetteville and Granite Wash, Las Animas and Sabine Systems for approximately $414 million; and • Proceeds of approximately $6 million related to the exchange of property, plant and equipment. Year Ended December 31, 2010: • Distribution of approximately $80 million to Quicksilver related to the purchase of the Alliance assets; and • Capital expenditures of approximately $69 million for gathering assets and facilities, including approximately $50 million related to the expansion of the Alliance System. Financing Activities Significant items impacting our financing activities during the three years ended December 31, 2012, 2011 and 2010 included the following: • • $218 million, $53 million and $11 million of net proceeds from the issuance of common units in 2012, 2011 and 2010; $153 million in net proceeds from the issuance of Class C units in 2011; 15 • • $6 million from the issuance of additional general partner units to maintain the General Partners’ 2% interest during 2012; $151 million net proceeds from the issuance of additional Senior Notes in 2012 and $200 million net proceeds from the issuance of Senior Notes in 2011; • Net repayments under our CMLP credit facility of $106 million in 2012; • Net borrowings under our CMM credit facility of $127 million in 2012; • Net borrowings under our CMLP credit facility of $29 million in 2011 and $158 million in 2010; and • The payment of Sabine System acquisition deferred payment of $8 million in 2012. During the year ended December 31, 2012, we paid distributions to our unitholders of approximately $104 million, which increased by $40 million when compared to 2011 and $54 million when compared to 2010. Off-Balance Sheet Arrangements We have no significant off-balance sheet arrangements. Contractual Obligations We are party to various contractual obligations. A portion of these obligations are reflected in our financial statements, such as long-term debt and other accrued liabilities, while other obligations, such as operating leases, capital commitments and contractual interest amounts are not reflected on our balance sheet. The following table and discussion summarizes our contractual cash obligations as of December 31, 2012, for each of the periods presented (In thousands): Long-term debt: Principal Interest Operating lease obligations Capital lease obligations Asset retirement obligations Other contractual liabilities and purchase obligations Due in Less than 1 Year Due in 1 to 3 years Due in 3 to 5 Years Thereafter Total $ — $ — $333,700 69,585 73,029 36,515 161 1,126 936 219 3,135 4,020 — — — — — 11,637 $351,461 33,906 15 — 14,024 — $685,161 213,035 2,238 7,374 14,024 11,637 Total contractual obligations $53,178 $77,290 $403,665 $399,406 $933,539 Long-term Debt (Principal and Interest). Debt obligations included in the table above represent stated maturities. Interest payments are shown through the stated maturity date of the related debt based on (i) the contractual interest rate for fixed rate debt or (ii) current market interest rates and the contractual credit spread for variable rate debt. Based on our debt outstanding and interest rates in effect at December 31, 2012, we estimate interest payments to be approximately $9 million annually on our credit facilities. For each additional $10 million in borrowings, annual interest payments will increase by approximately $0.6 million. If the committed amount under our credit facilities would have been fully utilized at December 31, 2012 at interest rates in effect at that time, annual interest expense would increase by approximately $12 million. If interest rates on our December 31, 2012 variable debt balance of $333.7 million increase or decrease by one percentage point, our annual income will decrease or increase by $3.4 million related to interest expense. For a further discussion of our debt obligations, see Item 8. Financial Statements and Supplementary Data, Note 5. Financial Instruments. Operating Leases. For a further discussion of these obligations, see Item 8. Financial Statements and Supplementary Data, Note 10. Commitments and Contingent Liabilities. 16 Capital Leases. For a further discussion of these obligations, see Item 8. Financial Statements and Supplementary Data, Note 10. Commitments and Contingent Liabilities. Other Contractual Liabilities and Purchase Obligations. Included in this amount are environmental obligations included in other current liabilities on our balance sheet. Other contractual purchase obligations are defined as legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations. Included in these amounts are commitments for purchasing equipment related to our construction projects. For a further discussion of our environmental liability and purchase obligations, see Item 8. Financial Statements and Supplementary Data, Note 10. Commitments and Contingent Liabilities. Critical Accounting Estimates Our significant accounting policies are described in Item 8. Financial Statements and Supplementary Data, Note 2. Basis of Presentation and Summary of Significant Accounting Policies. The preparation of financial statements in conformity with United States generally accepted accounting principles requires management to select appropriate accounting estimates and to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. We have discussed the development and selection of the following critical accounting estimates and related disclosures with the Audit Committee of the board of directors of our General Partner. Receivables At December 31, 2012, we had approximately $45 million of our accounts receivable which was primarily due from 11 customers and approximately $3 million of other receivables due from our insurance companies. We record these receivables based on an assessment of our ability to collect those receivables under the terms of the respective agreements under which they are due. We have not established an allowance for uncollectible amounts related to these accounts receivable based on our historical collection experience with our counterparties and our periodic assessment of their creditworthiness. These are significant judgments of management, and actual results could differ from these estimates of collectability. Long-Lived Assets Our long-lived assets consist primarily of property, plant and equipment and intangible assets that have been obtained through multiple historical business combinations. The initial recording of a majority of these long- lived assets was at fair value, which is estimated by management primarily utilizing market-related information and other projections on the performance of the assets acquired. Management reviews this information to determine its reasonableness in comparison to the assumptions utilized in determining the purchase price of the assets in addition to other market-based information that was received through the purchase process and other sources. Due to the imprecise nature of the projections and assumptions utilized in determining fair value, actual results can, and often do, differ from our estimates. We also utilize assumptions related to the useful lives and related salvage value of our long-lived assets in order to determine depreciation and amortization expense each period. Due to the imprecise nature of the projections and assumptions utilized determining useful lives, actual results can, and often do, differ from our estimates. We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset may be impaired. If an event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess 17 our ability to recover the carrying value of our assets based on our long-lived assets’ ability to generate future cash flows on an undiscounted basis. Projected cash flows of the asset are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. If those cash flow projections indicate that the long-lived asset’s carrying value is not recoverable, we record an impairment charge for the excess of carrying value of the asset over its fair value. The estimate of fair value considers a number of factors, including the potential value we would receive if we sold the asset, discount rates and projected cash flows. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates. During 2012, we recorded $1.6 million of impairments of our long-lived assets related to a fire at our Corvette processing plant. We did not record any impairments of our long-lived assets during 2011 or 2010. Goodwill Impairment Our goodwill represents the excess of the amount we paid for a business over the fair value of the net identifiable assets acquired. We have assigned our goodwill to three of our operating segments (Granite Wash, Fayetteville and Haynesville) which, based on management’s judgment, we also consider reporting units for goodwill assessment purposes. We evaluate goodwill for impairment annually on December 31, and whenever events or changes indicate that it is more likely than not that the fair value of a reporting unit could be less than its carrying amount. This evaluation requires us to compare the fair value of each of the three reporting units above to its carrying value (including goodwill). If the fair value exceeds the carry amount, goodwill of the reporting unit is not considered impaired. We estimate the fair value of our reporting units based on a number of factors, including the potential value we would receive if we sold the reporting unit, discount rates and projected cash flows. Projected cash flows of the reporting unit are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates. We did not record any impairments of goodwill during 2012, 2011 or 2010. We believe that a 10% decrease in our estimates of the fair value of our reporting units would not have resulted in an impairment being recorded on any of our goodwill, other than potentially the $4 million of goodwill associated with our Haynesville/Bossier Shale system as of December 31, 2012. Asset Retirement Obligations We have legal obligations to remove equipment and restore land when certain of our right-of-way agreements terminate or when certain of our long-lived assets reach the end of their economic life. We record a liability for the estimated cost of retiring those assets at fair value in the period in which the liability is legally or contractually incurred. The fair value is primarily based on our estimates of the amount and timing of asset retirement expenditures. We record subsequent adjustments to our asset retirement obligation liabilities if our estimates of the timing or the amount of the estimated cash flows change. We make several assumptions about the amount and timing of our asset retirement expenditures, which can include estimates of remaining lives of the wells connected to our systems, the estimated cost to remove equipment or restore land in the future, inflation factors and credit adjusted discount rates. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates. 18 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 a significant portion of our revenues, which causes us to be subject to the risk of nonpayment or late payment by Quicksilver. 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. As our largest customer, we remain dependent upon Quicksilver for a substantial percentage of our revenues and unless and until we further diversify our customer base, we expect to continue to be subject to non- diversified risk of nonpayment or late payment of our fees. However, our dependency on Quicksilver and the resulting credit risk has been reduced from prior periods through our recent acquisitions of additional midstream assets, including long term contracts with investment grade customers such as BHP, BP, XTO Energy, Devon, Antero and Enterprise Products and creditworthy producers such as Chesapeake. 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 failures to perform by our counterparties. 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. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates, for more information regarding our interest rate sensitivity. 19 Item 8. Financial Statements and Supplementary Data Index Below is an index to the items contained in Item 8, Financial Statements and Supplementary Data. Report of Independent Registered Public Accounting Firm Supplemental Consolidated Statements of Income Supplemental Consolidated Balance Sheets Supplemental Consolidated Statements of Cash Flows Supplemental Consolidated Statements of Changes in Partners’ Capital Notes to Supplemental Consolidated Financial Statements Supplemental Financial Information Supplemental Selected Quarterly Financial Information (Unaudited) Page 21 22 23 24 25 26 53 20 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Unitholders of Crestwood Midstream Partners LP We have audited the accompanying supplemental consolidated balance sheets of Crestwood Midstream Partners LP and subsidiaries (the “Partnership”) as of December 31, 2012 and 2011, and the related supplemental consolidated statements of income, cash flows, and changes in partners’ capital for each of the three years in the period ended December 31, 2012. These supplemental financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these supplemental 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 supplemental consolidated financial statements present fairly, in all material respects, the financial position of Crestwood Midstream Partners LP and subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. The supplemental consolidated financial statements give retroactive effect to the acquisition of Crestwood Marcellus Midstream LLC by the Partnership on January 8, 2013, which has been accounted for at historical cost as a reorganization of entities under common control as described in Note 1 to the supplemental consolidated financial statements. /s/ DELOITTE & TOUCHE LLP Houston, Texas March 18, 2013 21 CRESTWOOD MIDSTREAM PARTNERS LP SUPPLEMENTAL CONSOLIDATED STATEMENTS OF INCOME (In thousands, except for per unit data) Operating revenues Gathering revenue - related party Gathering revenue Processing revenue - related party Processing revenue Product sales Total operating revenues Operating expenses Product purchases Product purchases - related party Operations and maintenance General and administrative Depreciation, amortization and accretion Total operating expenses Gain from exchange of property, plant and equipment Operating income Interest and debt expense Income before income taxes Income tax expense (benefit) Net income General partner’s interest in net income Limited partners’ interest in net income Basic income per unit: Net income per limited partner unit Diluted income per unit: Net income per limited partner unit Year Ended December 31, 2012(1) 2011 2010 $ 88,091 74,922 25,652 8,481 42,317 $102,427 28,528 28,798 2,714 43,353 $ 77,645 5,749 27,590 2,606 — 239,463 205,820 113,590 23,853 15,152 43,108 29,582 51,908 38,787 — 36,303 24,153 33,812 163,603 133,055 — — 25,702 17,657 22,359 65,718 — 1,106 — 75,860 (35,765) 73,871 (27,617) 40,095 1,206 46,254 1,251 47,872 (13,550) 34,322 (550) $ 38,889 $ 45,003 $ 34,872 $ 22,218 $ 16,671 7,735 $ $ 37,268 2,526 $ $ 32,346 $ $ 0.37 0.37 $ $ 1.00 1.00 $ $ 1.11 1.03 (1) Financial information has been revised to include the results of Crestwood Marcellus Midstream LLC as discussed in Note 1. See accompanying notes. 22 CRESTWOOD MIDSTREAM PARTNERS LP SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS (In thousands, except for unit data) ASSETS Current assets Cash and cash equivalents Accounts receivable - related party Accounts receivable Insurance receivable Prepaid expenses and other assets Total current assets Property, plant and equipment, net of accumulated depreciation of $130,030 in 2012 and $89,860 in 2011 Intangible assets, net of accumulated amortization of $12,814 in 2012 and $2,440 in 2011 Goodwill Deferred financing costs, net Other assets Total assets LIABILITIES AND PARTNERS’ CAPITAL Current liabilities Accrued additions to property, plant and equipment Capital leases Deferred revenue Accounts payable - related party Accounts payable, accrued expenses and other liabilities Total current liabilities Long-term debt Long-term capital leases Asset retirement obligations Commitments and contingent liabilities (Note 10) Partners’ capital Common unitholders (41,164,737 and 32,997,696 units issued and outstanding at December 31, 2012 and 2011) Class C unitholders (7,165,819 and 6,596,635 units issued and outstanding at December 31, 2012 and 2011) General partner (979,614 and 763,892 units issued and outstanding at December 31, 2012 and 2011) Total partners’ capital Total liabilities and partners’ capital December 31, 2012(1) 2011 $ 111 $ 23,755 21,636 2,920 1,941 50,363 797 27,312 11,926 — 1,935 41,970 939,846 746,045 501,380 95,031 22,528 1,321 127,760 93,628 16,699 790 $1,610,469 $1,026,892 $ 9,213 $ 3,862 2,634 3,088 29,717 48,514 685,161 3,161 14,024 7,500 2,693 — 1,308 31,794 43,295 512,500 3,929 11,545 442,348 286,945 159,908 157,386 257,353 859,609 11,292 455,623 $1,610,469 $1,026,892 (1) Financial information has been revised to include the results of Crestwood Marcellus Midstream LLC as discussed in Note 1. See accompanying notes. 23 CRESTWOOD MIDSTREAM PARTNERS LP SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) Cash flows from operating activities Net income Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, amortization and accretion Deferred income taxes Equity-based compensation Gain from exchange of property, plant and equipment Other non-cash income items Changes in assets and liabilities: Accounts receivable - related party Accounts receivable Insurance receivable Prepaid expenses and other assets Accounts payable - related party Accounts payable, accrued expenses and other liabilities Net cash provided by operating activities Cash flows from investing activities Acquisitions, net of cash acquired Capital expenditures Proceeds from exchange of property, plant and equipment Proceeds from sale of property, plant and equipment Distributions to Quicksilver for Alliance assets Net cash used in investing activities Cash flows from financing activities Proceeds from issuance of senior notes Proceeds from CMLP credit facility Repayments of CMLP credit facility Proceeds from CMM credit facility Repayments of CMM credit facility Payment of Tristate Acquisition deferred payment Payments on capital leases Deferred financing costs paid Proceeds from issuance of Class C units, net Proceeds from issuance of common units, net Contributions from partners Distributions to partners Taxes paid for equity-based compensation vesting Net cash provided by financing activities Change in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period Supplemental cash flow information: Year Ended December 31, 2012(1) 2011 2010 $ 38,889 $ 45,003 $ 34,872 51,908 — 1,877 — 5,234 3,557 (7,076) (1,251) 2,113 1,780 5,034 102,065 33,812 — 916 (1,106) 3,473 (4,309) (7,348) — 249 (2,959) 18,600 86,331 22,359 (768) 5,522 — 4,961 (23,003) (270) — (903) 4,630 603 48,003 (563,965) (52,572) — 20 — (414,073) (48,405) 5,943 — — (616,517) (456,535) — (69,069) — — (80,276) (149,345) 151,500 411,700 (517,500) 143,500 (16,500) (7,839) (2,993) (11,322) — 217,483 249,680 (103,537) (406) 513,766 (686) 797 111 $ 200,000 215,200 (186,204) — 426,704 (268,600) — — — (1,966) (6,982) 152,671 53,550 8,741 (64,011) — 370,999 795 2 797 $ — — — — (13,568) — 11,054 — (49,699) (5,293) 100,598 (744) 746 2 8,590 $ $ Interest paid, net of amounts capitalized $ 27,885 $ 20,281 (1) Financial information has been revised to include the results of Crestwood Marcellus Midstream LLC as discussed in Note 1. See accompanying notes. 24 CRESTWOOD MIDSTREAM PARTNERS LP SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL (In thousands) Partners’ capital as of December 31, 2009 Issuance of units, net of offering costs Conversion of subordinated note payable Conversion of subordinated units Net income Equity-based compensation Taxes paid for equity-based compensation vesting Distributions to partners Distribution to Quicksilver Partners’ capital as of December 31, 2010 Issuance of units, net of offering costs Contributions by partners Net income Equity-based compensation Distributions to partners Partners’ capital as of December 31, 2011 Issuance of units, net of offering costs Contributions from partners Net income(1) Equity-based compensation Taxes paid for equity-based compensation vesting Distributions to partners(1) Limited Partners Subordinated Unitholders Class C Unitholders General Partner Total $ 3,040 — — 5,879 9,732 — — (18,651) — $ — $ — — — — — — — — 558 $ 284,837 11,054 — 57,736 — — — 34,872 2,526 5,522 — (5,293) — (49,699) (2,400) (80,276) — — — — — — — — — — — — — — 152,671 — 4,715 — — 157,386 — — 2,522 — — — 684 — 8,741 7,735 — (5,868) 11,292 — 249,680 22,218 — — (25,837) 258,753 206,221 8,741 45,003 916 (64,011) 455,623 217,483 249,680 38,889 1,877 (406) (103,537) Common $281,239 11,054 57,736 (5,879) 22,614 5,522 (5,293) (28,648) (80,276) 258,069 53,550 — 32,553 916 (58,143) 286,945 217,483 — 14,149 1,877 (406) (77,700) Partners’ capital as of December 31, 2012(1) $442,348 $ — $159,908 $257,353 $ 859,609 (1) Financial information has been revised to include the results of Crestwood Marcellus Midstream LLC as discussed in Note 1. See accompanying notes. 25 CRESTWOOD MIDSTREAM PARTNERS LP NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION AND DESCRIPTION OF BUSINESS Organization Crestwood Midstream Partners LP (CMLP) is a publicly traded Delaware limited partnership formed for the purpose of acquiring and operating midstream assets. Crestwood Gas Services GP LLC, our general partner (General Partner), is owned by Crestwood Holdings Partners LLC and its affiliates (Crestwood Holdings). Our common units are listed on the New York Stock Exchange (NYSE) under the symbol “CMLP.” On October 1, 2010, Quicksilver Resources Inc. (Quicksilver) sold all of its ownership interests in CMLP to Crestwood Holdings (Crestwood Transaction), the terms of which included: • Crestwood Holdings’ purchase of a 100% interest in our General Partner; • Crestwood Holdings’ purchase of 5,696,752 common units and 11,513,625 subordinated units; • Crestwood Holdings’ purchase of a $58 million subordinated promissory note (Subordinated Note) payable by CMLP which had a carrying value of approximately $58 million at closing; and • $701 million in cash paid to Quicksilver and conditional consideration in the form of potential additional cash payments from Crestwood Holdings in 2012 and 2013 of up to $72 million in the aggregate, depending upon achievement of certain defined average volume targets above an agreed threshold for 2011 and 2012, respectively. 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.” On October 18, 2010, subsequent to the closing of the Crestwood Transaction, the conflicts committee of our General Partner unanimously approved the conversion of our Subordinated Note payable into 2,333,712 common units in exchange for the outstanding balance of the Subordinated Note. In addition, on November 12, 2010, our subordination period ended resulting in the conversion of 11,513,625 subordinated units to common units on a one for one basis. On February 23, 2012, we and Crestwood Holdings formed the Crestwood Marcellus Midstream LLC (CMM) joint venture. We contributed approximately $131 million for a 35% membership interest and Crestwood Holdings contributed approximately $244 million for a 65% membership interest. We utilized available capacity under our CMLP credit facility to fund our contribution to CMM. In conjunction with the formation of CMM, we and Crestwood Holdings entered into a limited liability company agreement and an operating agreement governing CMM. On January 8, 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM for approximately $258 million, which was funded through $129 million of borrowings under our CMLP credit facility, the issuance of 6,190,469 Class D units, representing limited partner interests in us to Crestwood Holdings, and the issuance of 133,060 general partner units to our General Partner. As a result of the acquisition of the additional membership interest, we have the ability to control CMM’s operating and financial decisions and policies. We accounted for this transaction as a reorganization of entities under common control and accordingly, we have consolidated CMM and have retrospectively adjusted our historical financial statements as of and for the year ended December 31, 2012 to reflect the change in reporting entity. 26 Organizational Structure The following chart depicts our ownership structure as of December 31, 2012: Crestwood Holdings Partners LLC 100% Crestwood Holdings LLC Common LP Units 4.7% 2,333,712 100% Crestwood Gas Services GP LLC 100% GP 2.0% Class C LP Units 0.2% 108,387 Crestwood Gas Services Holdings LLC Common LP Units 34.9% 17,210,377 Class C LP Units 14.3% 7,057,432 Common LP Units 43.9% 21,620,648 Public Unitholders Public Unitholders Crestwood Midstream Partners LP (NYSE: CMLP) 100% Crestwood Marcellus Pipeline LLC 100% 100% Operating Subsidiaries Crestwood Marcellus Midstream LLC Our general partner and limited partner ownership interests as of December 31, 2012 are as follows: General partner interest Limited partner interests: Common unitholders Class C unitholders Total Crestwood Holdings Public Total 2.0% — 2.0% 39.6% 0.2% 41.8% 43.9% 83.5% 14.3% 14.5% 58.2% 100.0% See Note 4. Net Income Per Limited Partner Unit for additional information concerning ownership interests. Description of Business We are a growth-oriented midstream master limited partnership which owns and operates predominately fee-based gathering, processing, treating and compression assets servicing natural gas producers in the Barnett Shale in north Texas, the Fayetteville Shale in northwestern Arkansas, the Granite Wash in the Texas Panhandle, the Marcellus Shale in northern West Virginia, the Avalon Shale/Bone Spring in southeastern New Mexico, and the Haynesville/Bossier Shale in western Louisiana. 27 We conduct all of our operations in the midstream sector in eight operating segments, four of which are reportable. Our operating segments reflect how we manage our operations and are generally reflective of the geographic areas in which we operate. Our reportable segments consist of Barnett, Fayetteville, Granite Wash and Marcellus. We operate five systems located in basins that include NGL rich gas shale plays: (i) the Cowtown System; (ii) the Granite Wash System; (iii) the Las Animas Systems; and (iv) two systems in the Marcellus segment. 2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation Our consolidated financial statements are prepared in accordance with United States generally accepted accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of all intercompany accounts and transactions. In management’s opinion, all necessary adjustments to fairly present our results of operations, financial position and cash flows for the periods presented have been made and all such adjustments are of a normal and recurring nature. In 2012, we reclassified approximately $2.7 million from goodwill to accounts receivable and other current assets to reflect the fair value of certain contracts acquired in the Frontier Gas Acquisition (as defined in Note 3. Acquisitions) that were not recorded when the purchase price allocation was finalized for the acquired assets. This reclassification had no impact on previously reported net income, earnings per unit or partners’ capital. On January 8, 2013, we acquired Crestwood Holdings 65% membership interest in CMM and as a result, we control the operating and financial decisions of CMM. We accounted for this transaction as a reorganization of entities under common control and the accounting standards related to such transactions requires us to retroactively adjust our historical results. The following tables summarize the impact of our consolidation of CMM as of and for the year ended December 31, 2012. CMM was formed on February 23, 2012, therefore we did not adjust our historical results for periods prior to the inception date of CMM. Earnings related to the recast of our historical results due to the acquisition of our 65% membership interest in CMM were allocated to the General Partner. As a result, there was no impact to our basic or diluted earnings per limited partner unit. Year Ended December 31, 2012 As Previously Reported CMM Combined (In thousands, except per unit data) $ 25,502 (12,365) $ 213,961 (151,238) $ 239,463 (163,603) $ 62,723 $ 13,137 $ 75,860 $ $ 0.37 0.37 45,223 45,420 $ $ 0.37 0.37 45,223 45,420 Operating revenues Operating expenses Operating income Basic earnings per limited partner unit Diluted earnings per limited partner unit Weighted-average number of limited partner units: Basic Diluted 28 ASSETS Current assets Cash and cash equivalents Accounts receivable - related party Accounts receivable Other current assets Total current assets Investment in unconsolidated affiliate Property, plant and equipment, net Intangible assets, net Other long-term assets Total assets As of December 31, 2012 As Previously Presented CMM Eliminations Combined $ 90 $ $ 21 23,863 15,123 4,861 43,868 128,646 784,371 163,021 113,501 — 6,513 — 6,603 — 155,475 338,359 5,379 — $ (108) — — (108) (128,646) — — — 111 23,755 21,636 4,861 50,363 — 939,846 501,380 118,880 $1,233,407 $505,816 $(128,754) $1,610,469 LIABILITIES AND PARTNERS’ CAPITAL/MEMBERS’ EQUITY Current liabilities Accrued additions to property, plant and equipment Other current liabilities Accounts payable, accrued expenses and other liabilities $ Total current liabilities Long-term debt Other long-term liabilities Partner’s capital/members’ equity 3,829 6,950 27,423 38,202 558,161 16,349 620,695 $ 5,384 2,634 2,402 10,420 127,000 836 367,560 $ — $ — (108) (108) — — (128,646) 9,213 9,584 29,717 48,514 685,161 17,185 859,609 Total liabilities and partners’ capital/members’ equity $1,233,407 $505,816 $(128,754) $1,610,469 Principles of Consolidation We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We do not have ownership in any variable interest entities. Use of Estimates The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can differ from those estimates. Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of less than three months to be cash or cash equivalents. Our cash equivalents consist primarily of temporary investments of cash in short-term money market instruments. Accounts Receivable Our accounts receivable are primarily due from Quicksilver and Antero Resources Appalachian Corporation (Antero). 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 to 60 days. We regularly review collectability and establish an allowance 29 as necessary using the specific identification method. At December 31, 2012 and 2011, we have recorded no allowance for uncollectible accounts receivable. During the years ended December 31, 2012, 2011 and 2010, we experienced no significant non-payment for services. Long-Lived Assets Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and interest. We capitalize major units of property replacements or improvements and expense minor items. We use the straight-line method to depreciate property, plant and equipment over the estimated useful lives of the assets. When we retire property, plant and equipment, we charge accumulated depreciation for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less their salvage value. We include gains or losses on dispositions of assets in operations and maintenance expense in our consolidated statements of income. Our intangible assets consist of acquired gas gathering, compression and processing contracts. We amortize these contracts based on the projected cash flows associated with the contracts. We evaluate our long-lived assets for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate the recoverability of our carrying value based on the long-lived asset’s ability to generate future cash flows on an undiscounted basis. If the undiscounted cash flows are not sufficient to recover the long-lived asset’s carrying value, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying values of the asset downward, if necessary, to their estimated fair value. Our fair value estimates are generally based on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted cash flows. Goodwill Goodwill represents consideration paid in excess of the fair value of the identifiable assets acquired in a business combination. We evaluate goodwill for impairment, at a minimum, annually on December 31, or whenever facts and circumstances indicate that fair value of a reporting unit is less than its carrying amount. When testing goodwill for impairment, we assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than the carrying amount as the basis to determine if a two- step quantitative impairment test is required. Under the two-step quantitative test, the first step compares the fair value of the reporting unit to its carrying value, including goodwill. If the fair value exceeds the carry amount, goodwill of the reporting unit is not considered impaired. If however, the fair value does not exceed the carrying amount the second step compares the implied fair value to the carrying value of the reporting unit. If the carrying amount of a reporting unit’s goodwill exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied value is recognized as an impairment loss. Deferred Financing Costs Costs associated with obtaining long-term debt are amortized over the term of the related debt using the effective interest method. 30 Asset Retirement Obligations We record a liability for legal or contractual obligations to retire our long-lived assets associated with right- of-way contracts we hold and our facilities whether owned or leased. We record a liability in the period the obligation is incurred and estimable. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation, amortization and accretion expense in our consolidated statements of income. Environmental Costs and Other Contingencies We recognize liabilities for environmental and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued. We record liabilities for environmental contingencies at their undiscounted amounts on our consolidated balance sheets as accounts payable, accrued expenses and other liabilities when environmental assessments indicate that remediation efforts are probable and costs can be reasonable estimated. Estimates of our liabilities are based on currently available facts and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods. We evaluate potential recoveries of amounts from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidate balance sheet. Revenue Recognition We gather, process, treat, compress, transport and sell natural gas pursuant to fixed-fee and percent-of- proceeds contracts. For fixed-fee contracts, we recognize revenues based on the volume of natural gas gathered, processed and treated or compressed. For percent-of-proceeds contracts, we recognize revenues based on the value of products sold to third parties. We recognize revenues for our services and products when all of the following criteria are met: • • • • persuasive evidence of an exchange arrangement exists; services have been rendered or products delivered; the price for services is fixed or determinable; and collectability is reasonably assured. Income Taxes We are a partnership for income tax purposes and are not subject to either federal income taxes or generally to state income taxes. Our partners are responsible for their share of taxable income which may differ from income for financial statement purposes due to differences in the tax basis and financial reporting basis of assets and liabilities. We are responsible for our portion of the Texas Margin tax that is included in Crestwood Holdings’ consolidated Texas franchise tax return. Our current tax liability will be assessed based on 0.7% of the gross 31 revenue apportioned to Texas. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax. Equity Based Compensation Equity-based awards are valued at the closing market price of our common units on the date of grant, which reflects the fair value of such awards. For those awards that are settled in cash, the associated liability is remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. We generally recognize the expense associated with the award over the vesting period. At the time of issuance of phantom units, management of our General Partner determines whether they will be settled in cash or settled in our common units. 3. ACQUISITIONS 2012 Acquisitions Antero Acquisition On February 24, 2012, we announced the execution of an Asset Purchase Agreement related to the acquisition of gathering assets owned by Antero in the Marcellus Shale located in Harrison and Doddridge Counties, West Virginia (Antero Acquisition), and, at closing, the planned execution of a 20 year Gas Gathering and Compression Agreement (GGA) with Antero. On March 26, 2012, CMM completed the Antero Acquisition for approximately $380 million. The assets acquired by CMM consisted of a 33 mile low pressure gathering system at the time of acquisition. The gathering pipelines deliver Antero’s Marcellus Shale production to various regional pipeline systems including Columbia, Dominion and Equitrans and Mark West Energy Partners’ Sherwood Gas Processing Plant. The GGA with Antero provided for an area of dedication at the time of acquisition of approximately 127,000 gross acres, or 104,000 net acres, largely located in the rich gas corridor of the southwestern core of the Marcellus Shale play. As part of the GGA, Antero committed to deliver minimum annual throughput volumes to us for a seven year period from January 1, 2012 to January 1, 2019, ranging from an average of 300 MMcf/d in 2012 to an average of 450 MMcf/d in 2018. During the period ended December 31, 2012, Antero delivered less than the minimum annual throughput volumes and at December 31, 2012, we recorded a receivable and deferred revenue of approximately $2.6 million due to Antero’s potential ability to recover this amount if Antero’s 2013 throughput volumes exceed the minimum annual throughput volumes included in the GGA for 2013. The final purchase price allocation is as follows (In thousands): Purchase price: Cash Total purchase price Purchase price allocation: Property, plant and equipment Intangible assets Total assets Asset retirement obligation Total liabilities Total 32 $381,718 $381,718 $ 90,562 291,218 $381,780 $ $ 62 62 $381,718 Our intangible assets recorded as result of the Antero Acquisition relate to the GGA with Antero. These intangible assets will be amortized over the life of the contract. Transaction costs for the Antero Acquisition for the year ended December 31, 2012 were approximately $0.6 million and were included in general and administrative expenses in our consolidated statement of income. For the period from the acquisition date (March 26, 2012) through December 31, 2012, we recorded approximately $26 million of operating revenues and $12 million of operating expenses related to the operations of the assets acquired from Antero. Devon Acquisition On August 24, 2012, we acquired certain gathering and processing assets in the NGL rich gas region of the Barnett Shale from Devon Energy Corporation (Devon) for approximately $87 million (Devon Acquisition). The assets acquired consist of a 74 mile low pressure natural gas gathering system, a cryogenic processing facility with capacity of 100 MMcf/d and 23,100 hp of compression equipment, and are located in Johnson County, Texas (West Johnson County System) near our Cowtown gathering system. Additionally, as part of the transaction, we entered into a 20 year, fixed-fee gathering, processing and compression agreement with Devon, under which we gather and process Devon’s natural gas production from a 20,500 acre dedication. The final purchase price allocation is pending the completion of the valuation of the assets acquired and liabilities assumed. The preliminary purchase price allocation is as follows (In thousands): Purchase price: Cash Total purchase price Preliminary purchase price allocation: Property, plant and equipment Intangible assets Total assets Asset retirement obligation Property tax liability Environmental liability Total liabilities Total $87,247 $87,247 $41,555 46,959 $88,514 $ 540 527 200 $ 1,267 $87,247 Our intangible assets recorded as a result of the Devon Acquisition relate to the 20 year fixed-fee gathering, processing and compression agreement with Devon. These intangible assets will be amortized over the life of the contract. Transactions costs for the Devon Acquisition for the year ended December 31, 2012 were approximately $1 million are included in general and administrative expenses in our consolidated statement of income. For the period from the acquisition date (August 24, 2012) through December 31, 2012, we recorded approximately $7 million of operating revenues and $5 million of operating expenses related to the operations of the assets acquired from Devon. We did not incur any significant non-operating income or expenses related to the acquired assets during that period. We believe that it is impracticable to present financial information for the acquired assets prior to the acquisition date due to the lack of availability of historical financial information related to the acquired assets, and because the 20 year fixed-fee gathering, processing and compression agreement with Devon has significantly different terms than the historical intercompany relationships between the acquired assets and Devon. 33 EMAC Acquisition On December 28, 2012, CMM acquired all of the membership interest of E. Marcellus Asset Company, LLC (EMAC) from Enerven Compression, LLC (Enerven) for approximately $95 million. We financed this acquisition through our CMM $200 million Credit Facility. EMAC’s assets consist of four compression and dehydration stations located on our gathering systems in Harrison County, West Virginia. These assets will provide compression and dehydration services to Antero under a compression services agreement through 2018. Antero has the option to renew the agreement for an additional five years upon expiration of the original agreement. The final purchase price allocation is pending the completion of the valuation of the assets acquired and liabilities assumed. The preliminary purchase price allocation is as follows (In thousands): Purchase price: Cash Total purchase price Preliminary purchase price allocation: Property, plant and equipment Intangible assets Total assets Asset retirement obligation Total liabilities Total $95,000 $95,000 $45,938 49,817 $95,755 $ $ 755 755 $95,000 Our intangible assets recorded as result of the EMAC acquisition relate to the compression services agreements with Antero. These intangible assets will be amortized over the life of the contract. Transaction costs for the EMAC acquisition for the year ended December 31, 2012 were approximately $0.3 million and were included in general and administrative expenses in our consolidated statement of income. The acquisition of EMAC was not material to our results of operations for the period from the acquisition date (December 28, 2012) to December 31, 2012. 2011 Acquisitions Las Animas Acquisition On February 16, 2011, we acquired certain midstream assets in the Avalon Shale trend from a group of independent producers for approximately $5 million (Las Animas Acquisition). The assets acquired consisted of approximately 46 miles of natural gas gathering pipeline located in the Morrow/Atoka trend and the Avalon Shale trend in southeastern New Mexico. The pipelines are supported by long-term fixed-fee contracts which include existing Morrow/Atoka production and dedications of approximately 55,000 acres. The Las Animas Acquisition was recorded in property, plant and equipment at fair value of approximately $5 million. During the year ended December 31, 2011, we recognized approximately $5 million of operating revenues and $0.1 million of operating income related to this acquisition. Frontier Gas Acquisition On April 1, 2011, we acquired certain midstream assets in the Fayetteville Shale and the Granite Wash from Frontier Gas Services, LLC for approximately $345 million (Frontier Gas Acquisition). We financed $338 million of the purchase price through a combination of equity and debt as described in Note 5. Financial Instruments and Note 14. Partners’ Capital. 34 The Fayetteville assets acquired consisted of approximately 130 miles of high pressure and low pressure gathering pipelines in northwestern Arkansas with capacity of approximately 510 MMcf/d, treating capacity of approximately 165 MMcf/d and approximately 35,000 hp compression (Fayetteville System). The Fayetteville System interconnects with multiple interstate pipelines which serve the Fayetteville Shale and are supported by long-term fixed-fee contracts with producers who dedicated approximately 100,000 acres in the core of the Fayetteville Shale to us. These contracts have initial terms that extend through 2020 and include an option, by either party to the contract, to extend the contract through 2025. The Granite Wash assets acquired consisted of a 28 mile pipeline system and a 36 MMcf/d cryogenic processing plant in the Texas Panhandle (Granite Wash System). The Granite Wash System is supported by more than 13,000 dedicated acres and long-term contracts with initial terms that extend through 2022. During 2011, we finalized the Frontier Gas Acquisition purchase price allocation, which resulted in the recognition of approximately $94 million in goodwill, of which $77 million was allocated to the Fayetteville segment and $17 million was allocated to the Granite Wash segment. The final purchase price allocation is as follows (In thousands): Purchase price: Cash Purchase price allocation: Accounts receivable Prepaid expenses and other Property, plant and equipment Intangible assets Goodwill Other assets Total assets Current portion of capital leases Accounts payable, accrued expenses and other Long-term capital leases Asset retirement obligations Total liabilities Total $344,562 $ 335 750 144,505 114,200 93,628 178 $353,596 $ 2,576 64 6,011 383 $ 9,034 $344,562 Transactions costs for the Frontier Gas Acquisition for the year ended December 31, 2011 were approximately $5 million of which approximately $2 million was recorded in general and administrative expense and $3 million was recorded in interest expense. During the year ended December 31, 2011, we recognized approximately $59 million in operating revenues and $5 million in operating income related to this acquisition. Tristate Acquisition On November 1, 2011, we acquired Tristate Sabine, LLC (Tristate) from affiliates of Energy Spectrum Capital, Zwolle Pipeline, LLC, and Tristate’s management for approximately $72 million in cash consideration comprised of $64 million paid at closing plus a deferred payment of approximately $8 million, which was paid during the fourth quarter of 2012 (Tristate Acquisition). At the time of acquisition, the Tristate assets located in Haynesville/Bossier Shale consisted of approximately 60 miles of high pressure and low pressure gathering pipelines in western Louisiana with capacity of approximately 100 MMcf/d and treating capacity of approximately 80 MMcf/d (Sabine System). The Sabine System is supported by long-term, fixed-fee contracts with producers who dedicated approximately 20,000 acres to us. These contracts have various initial terms that extend through 2019 and 2021. 35 During 2012, we finalized our purchase price allocation for the Tristate Acquisition, which resulted in the recognition of approximately $4 million in goodwill, primarily related to anticipated operating synergies between the assets acquired and our existing assets. The final purchase price allocation is as follows (In thousands): Purchase price: Cash Deferred payment Total purchase price Purchase price allocation: Cash Accounts receivable Prepaid expenses and other Property, plant and equipment Intangible assets Goodwill Total assets Accounts payable, accrued expenses and other Asset retirement obligation Total liabilities Total $64,359 8,000 $72,359 $ 589 2,564 364 55,568 12,000 4,053 $75,138 $ 1,915 864 $ 2,779 $72,359 Transaction costs of $0.3 million were recognized in general and administrative expense during 2011. During the year ended December 31, 2011, we recognized approximately $1.9 million in operating revenues and $0.9 million in operating income related to this acquisition. Unaudited Pro Forma Information The following table is the presentation of income for the year ended December 31, 2012 as if we had completed the EMAC acquisition on February 23, 2012, the inception date of CMM, which acquired EMAC (In thousands, except per unit data): Operating revenues Operating expenses Operating income Year Ended December 31, 2012 Crestwood Midstream Partners LP $ 239,463 (163,603) Proforma Adjustment (1) $ 9,950 (7,168) Combined $ 249,413 (170,771) $ 75,860 $ 2,782 $ 78,642 Basic earnings per limited partner unit(2) Diluted earnings per limited partner unit (2) Weighted-average number of limited partner units: (2) Basic Diluted $ $ 0.37 0.37 45,223 45,420 $ $ 0.37 0.37 45,223 45,420 (1) Represents approximately ten months of operating income for the EMAC acquisition prior to the (2) acquisition. Earnings related to the recast of our historical results due to the acquisition of our 65% membership interest in CMM were allocated to the General Partner. As a result, there was no impact to our basic or diluted earnings per limited partner unit. 36 The following tables are the presentation of income for the years ended December 31, 2011 and 2010 as if we had completed the Las Animas, Frontier Gas and Tristate Acquisitions on January 1, 2010 (In thousands, except per unit data): Operating revenues Operating expenses, net of gain from Year Ended December 31, 2011 Crestwood Midstream Partners LP (1) Proforma Adjustment (2) Combined $ 205,820 $ 25,827 $ 231,647 exchange of property, plant and equipment (131,949) (22,911) (154,860) Operating income $ 73,871 $ 2,916 $ 76,787 Basic earnings per limited partner unit: Diluted earnings per limited partner unit: Weighted-average number of limited partner units: Basic Diluted $ $ 1.00 1.00 37,206 37,320 $ $ 0.87 0.87 38,835 38,949 Operating revenues Operating expenses Operating income Year Ended December 31, 2010 Crestwood Midstream Partners LP $113,590 (65,718) Proforma Adjustment (3) $ 74,217 (70,295) Combined $ 187,807 (136,013) $ 47,872 $ 3,922 $ 51,794 Basic earnings per limited partner unit: Diluted earnings per limited partner unit: Weighted-average number of limited partner units: Basic Diluted $ $ 1.11 1.03 29,070 31,316 $ $ 0.80 0.75 35,561 37,807 (1) Includes eleven months of operating income for the Las Animas Acquisition, nine months of operating income for the Frontier Gas Acquisition and two months of operating income for the Tristate Acquisition. (2) Represents approximately one month of operating income for the Las Animas Acquisition, three months of operating income for the Frontier Gas Acquisition and ten months of operating income for the Tristate Acquisition, prior to the respective acquisition. (3) Represents operating income for the Las Animas Acquisition, the Frontier Gas Acquisition and the Tristate Acquisition for the year ended December 31, 2010. 4. NET INCOME PER LIMITED PARTNER UNIT AND DISTRIBUTIONS 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 limited partner units from the potential issuance of limited partner units. 37 The tables below show the (i) allocation of net income attributable to limited partners and the (ii) net income per limited partner unit based on the number of basic and diluted limited partner units outstanding for the years ended December 31, 2012, 2011 and 2010. Allocation of Net Income to General Partner and Limited Partners Net income GP’s incentive distributions Year Ended December 31, 2012 2011 2010 $ 38,889 (14,753) $45,003 (7,049) $34,872 (2,016) Net income after incentive distributions GP’s interest in net income after incentive distributions 24,136 7,465 37,954 686 32,856 510 LP’s interest in net income after incentive distributions $ 16,671 $37,268 $32,346 Net Income Per Limited Partner Unit Limited partners’ interest in net income Weighted-average limited partner units - basic (1) Effect of unvested phantom units Year Ended December 31, 2012 2011 2010 $16,671 45,223 197 $37,268 37,206 114 $32,346 29,070 2,246 Weighted-average limited partner units - diluted (1) 45,420 37,320 31,316 Basic earnings per unit: Net income per limited partner Diluted earnings per unit: Net income per limited partner $ $ 0.37 0.37 $ $ 1.00 1.00 $ $ 1.11 1.03 (1) Includes 6,869,268 and 4,828,093 Class C units for the years ended December 31, 2012 and 2011. There were no units excluded from our dilutive earnings per share as we do not have any anti-dilutive units for the years ended December 31, 2012, 2011 and 2010. Distributions. Our Second Amended and Restated Agreement of Limited Partnership, dated February 19, 2008, as amended (Partnership Agreement), requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash (as defined therein) to unitholders of record on the applicable record date, as determined by our General Partner. Our minimum quarterly distribution is $0.30 per unit, to the extent we have sufficient cash flows from operations after the establishment of cash reserve and payment of fees and expenses, including payments to our General Partner. There is no guarantee that we will pay the minimum quarterly distribution in any quarter. We are prohibited from making any distributions to unitholders if such distribution would cause an event of default or an event of default exists, under our Credit Facility or other agreements governing our long-term debt. General Partner Interest and Incentive Distribution Rights. Our General Partner is entitled to quarterly distributions equal to its General Partner interest. As of December 31, 2012, our General Partner interest is approximately 2%, represented by 979,614 General Partner units. Our General Partner has the right, but not the obligation, to contribute a proportional amount of capital to us to maintain its current General Partner interest. The General Partner’s interest in our distributions will be reduced if we issue additional units in the future and our General Partner does not contribute a proportional amount of capital to us to maintain its General Partner interest. 38 Our General Partner holds incentive distribution rights (IDRs) in accordance with the Partnership Agreement. These rights pay an increasing percentage, up to a maximum of 50% of the cash we distribute from operating surplus in excess of $0.45 per unit per quarter. The maximum distribution of 50% includes distributions paid to our General Partner based on its General Partner interest and assumes that our General Partner maintains its current General Partner interest. The maximum distribution of 50% does not include any distributions that our General Partner may receive on limited partner units that it owns. The following table presents distributions for 2012 and 2011 (In millions, except per unit data): Distribution Paid Limited Partners General Partner Payment Date Attributable to the Quarter Ended Per Unit Distribution Cash paid to common Paid-In- Kind Value to Class C unitholders Cash paid to General Partner and IDR Paid-In- Kind Value to Class C unitholders Total Cash Total Distribution 2013 February 12, 2013 December 31, 2012 2012 November 9, 2012 August 10, 2012 May 11, 2012 February 10, 2012 December 31, 2011 September 30, 2012 June 30, 2012 March 31, 2012 2011 November 10, 2011 September 30, 2011 August 12, 2011 May 13, 2011 February 11, 2011 December 31, 2010 June 30, 2011 March 31, 2011 $0.51 $21.0 $ 3.7 $4.1 $ 0.6 $25.1 $29.4 $0.51 $0.50 $0.50 $0.49 $0.48 $0.46 $0.44 $0.43 $21.0 $20.6 $18.2 $17.9 $15.8 $15.2 $13.7 $13.4 $ 3.5 $ 3.4 $ 3.4 $ 3.2 $ 3.1 $ 2.9 $ 2.7 $— $4.1 $3.7 $3.3 $2.8 $2.3 $1.6 $1.1 $0.9 $ 0.6 $ 0.5 $ 0.5 $ 0.5 $ 0.4 $ 0.2 $ 0.2 $— $25.1 $24.3 $21.5 $20.7 $18.1 $16.8 $14.8 $14.3 $29.2 $28.2 $25.4 $24.4 $21.6 $19.9 $17.7 $14.3 Our Class C units are substantially similar in all respects to our existing common units, representing limited partner interests, except that we have the option to pay distributions to our Class C unitholders with cash or by issuing additional Paid-In-Kind Class C units based upon the volume weighted-average price of our common units for the 10 trading days immediately preceding the date the distribution is declared. We issued 633,084 and 473,731 additional Class C units in lieu of paying in cash quarterly distributions on our Class C units for the years ended December 31, 2012 and 2011. In February 2013, we issued an additional 183,995 Class C units in quarterly distributions. Additionally, in April 2013, our outstanding Class C units will convert to common units on a one-for-one basis. Quarterly distributions on these converted units will be paid with cash. In conjunction with the acquisition of the 65% membership interest in CMM in January 2013, we issued 6,190,469 Class D units, representing limited partner interests in us to Crestwood Holdings. Our Class D units are similar in certain respects to our existing common units and Class C units, except that we have the option to pay distributions to our Class D unitholders for a period of one year with cash or by issuing additional Paid-In- Kind Class D units based upon the volume weighted-average price of our common units for the 10 trading days immediately preceding the date the distribution is declared. The Class D units issued in January 2013 will not participate in the dividend paid on February 12, 2013. In March 2014, our outstanding Class D units will convert to common units on a one-for-one basis. 5. FINANCIAL INSTRUMENTS Fair Values We separate the fair values of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Our assessment and classification of an instrument within a level can change over time based on the maturity or liquidity of the instrument and would be reflected at the end of the period in which the 39 change occurs. During the years ended December 31, 2012 and 2011, there have been no changes to the inputs and valuation techniques used to measure fair value, the types of instruments, or the levels in which they are classified. Cash and Cash Equivalents, Accounts Receivable and Accounts Payable. As of December 31, 2012 and 2011, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair value based on the short-term nature of these instruments. Credit Facilities. The fair value of our credit facilities approximates their carrying amounts as of December 31, 2012 and 2011 due primarily to the variable nature of the interest rate of the instruments, which is considered a Level 2 fair value measurement. Senior Notes. We estimated the fair value of our Senior Notes (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances. The following table reflects the carrying value and fair value of our Senior Notes (In millions): Senior Notes Debt As of December 31, 2012 2011 Carrying Amount Fair Value Carrying Amount Fair Value $ 351 $ 365 $ 200 $ 197 Our long-term debt consisted of the following at December 31 (In thousands): CMM Credit Facility, due March 2017 CMLP Credit Facility, due November 2017 Senior Notes, due April 2019 Plus: Unamortized premium on Senior Notes Total long-term debt 2012 2011 $ 127,000 206,700 350,000 683,700 1,461 $ — 312,500 200,000 512,500 — $ 685,161 $ 512,500 Credit Facilities CMM Credit Facility. On March 26, 2012, in conjunction with the acquisition of Antero’s gathering system assets, we entered into a credit agreement with certain lenders. The five year term credit agreement allows for revolving loans, letters of credit and swingline loans in an aggregate principal amount of up to $200 million (CMM Credit Facility). The CMM Credit Facility is secured by substantially all its assets. Borrowings under the CMM Credit Facility bear interest at the London Interbank Offered Rate (LIBOR) plus an applicable margin or a base rate as defined in the credit agreement. Under the terms of the CMM Credit Facility, the applicable margin under LIBOR borrowings was 2.5%. The weighted-average interest rate as of December 31, 2012 was 2.8%. Our borrowings under the CMM Credit Facility were $127 million as of December 31, 2012, and based on our results through December 31, 2012, our remaining available capacity under the credit facility was $59 million. For the period from March 26, 2012 to December 31, 2012, our average and maximum outstanding borrowings were approximately $18 million and $130 million. 40 Our CMM Credit Facility requires us to maintain: • • a ratio of our trailing 12-month EBITDA (as defined in the credit agreement) to our net interest expense of not less than 2.0 to 1.0; and a ratio of total indebtedness to trailing 12-month EBITDA (as defined in the credit agreement) of not more than 4.5 to 1.0, or not more than 5.0 to 1.0 for up to nine months following certain acquisitions. CMLP Credit Facility. Our senior secured credit facility, as amended (CMLP Credit Facility), allows for revolving loans, letters of credit and swingline loans in an aggregate amount of up to $550 million. Our CMLP Credit Facility matures on November 16, 2017 and is secured by substantially all of our assets and those of certain of our subsidiaries. As of December 31, 2012, our Credit Facility is guaranteed by our 100% owned subsidiaries except for CMM and its consolidated subsidiaries. Borrowings under the CMLP 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 CMLP Credit Facility, the applicable margin under LIBOR borrowings was 2.5% and 3.0% at December 31, 2012 and 2011. The weighted-average interest rate as of December 31, 2012 and 2011 was 2.8% and 3.3%. Our borrowings under the CMLP Credit Facility were approximately $207 million and $312 million as of December 31, 2012 and 2011, and based on our results through December 31, 2012, our remaining available capacity under the CMLP Credit Facility was $167 million. For the year ended December 31, 2012 and 2011, our average outstanding borrowings were $305 million and $325 million. For the year ended December 31, 2012 and 2011, our maximum outstanding borrowings were $375 million and $282 million. Our CMLP Credit Facility requires us to maintain: • • a ratio of our consolidated trailing 12-month EBITDA (as defined in the CMLP Credit Facility) to our net interest expense of not less than 2.5 to 1.0; and a ratio of total indebtedness to consolidated trailing 12-month EBITDA (as defined in the CMLP Credit Facility) 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 of December 31, 2012, we were in compliance with the financial covenants under our CMM and CMLP credit facilities. Our credit facilities contain 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. An event of default may result in the acceleration of our repayment of outstanding borrowings under the Credit Facility, the termination of the Credit Facility and foreclosure on collateral. Senior Notes On April 1, 2011, we issued $200 million of senior notes, which accrue interest at the rate of 7.75% per annum and mature in April 2019. On November 8, 2012, we issued an additional $150 million of these notes in a private placement offering. The $150 million senior notes have the same terms as our $200 million senior notes. The net proceeds from the offering were used to reduce our indebtedness under our Credit Facility. Our obligations under the Senior Notes are guaranteed on an unsecured basis by certain of our current and future domestic subsidiaries. Interest is payable semi-annually in arrears on April 1 and October 1 of each year. Our Senior Notes require us to maintain a ratio of our consolidated trailing 12-month EBITDA (as defined in the indenture governing the Senior Notes) to fixed charges of at least 1.75 to 1.0. As of December 31, 2012, we were in compliance with this covenant. 41 Bridge Loans In February 2011, in connection with the Frontier Gas Acquisition, we obtained commitments from multiple lenders for senior unsecured bridge loans in an aggregate amount up to $200 million. The commitment was terminated on April 1, 2011 in conjunction with the issuance of the Senior Notes described above. We incurred approximately $3 million of commitment fees during the year ended December 31, 2011, which was included in interest expense on our consolidated statement of income. Subordinated Note In August 2007, we executed the Subordinated Note payable to Quicksilver in the principal amount of $50 million. The Subordinated Note was assigned to Crestwood Holdings as part of the Crestwood Transaction on October 1, 2010. Our Credit Facility required us to terminate the Subordinated Note through the issuance of additional common units during 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. We issued 2,333,712 of our common units to Crestwood Holding in exchange for the outstanding balance of the Subordinated Note at the time of the conversion. 6. PROPERTY, PLANT AND EQUIPMENT The table below presents the details of our property, plant and equipment (In thousands): Gathering systems Processing plants and compression facilities Rights-of-way and easements Buildings and other Land Construction in progress Property, plant and equipment Accumulated depreciation Property, plant and equipment, net Depreciable Life 2012 2011 December 31, 20 years 20-25 years 20 years 5-40 years — — $ 450,989 490,991 60,502 7,385 4,698 55,311 $298,207 429,908 50,085 5,958 4,674 47,073 1,069,876 (130,030) 835,905 (89,860) $ 939,846 $746,045 We have capital lease assets of approximately $12 million and $9 million included in our property, plant and equipment at December 31, 2012 and 2011. During the year ended December 31, 2012, we recorded an impairment of approximately $1.6 million of our property, plant and equipment to write certain of our assets down to their fair value of zero (which is a Level 3 fair value measurement) as a result of a compressor building fire that occurred on September 6, 2012 at our Corvette processing plant in our Barnett Segment. This impairment, in addition to approximately $1.3 million of other operations and maintenance costs incurred related to the incident, is recoverable under our insurance policies and is recorded in Prepaid Expenses and Other current assets on our balance sheet as of December 31, 2012. During the year ended December 31, 2011, we recorded a gain of approximately $1 million on the exchange of property, plant and equipment under an agreement with a third party to exchange the delivery of certain processing plants that were under contract. We received proceeds of approximately $6 million on the exchange. 42 7. INTANGIBLE ASSETS Our intangible assets consist of acquired gas gathering, compression and processing contracts. The following table presents the changes in our intangible assets (In thousands): Net intangible assets at January 1 Additions Amortization expense Net intangible assets at December 31 December 31, 2012 2011 $127,760 383,994 (10,374) $ — 130,200 (2,440) $501,380 $127,760 Our gas gathering and processing contracts have useful lives of 5 to 20 years, as determined based upon the anticipated life of the contracts with our customers. The expected amortization of our intangible assets as of December 31, 2012 for the next five years and in total thereafter is as follows (In thousands): 2013 2014 2015 2016 2017 Thereafter Total $ 21,983 23,832 25,144 26,414 28,678 375,329 $501,380 8. ACCOUNTS PAYABLE, ACCRUED EXPENSES AND OTHER LIABILITIES The table below presents the details of our accounts payable, accrued expenses and other liabilities (In thousands): Accrued expenses Accrued property taxes Accrued product purchases payable Tax payable Interest payable Accounts payable Tristate Acquisition deferred payment (Note 3) Other December 31, 2012 2011 $ 9,608 5,638 2,450 2,159 7,505 2,278 — 79 $ 3,175 5,204 3,594 1,545 4,788 5,128 8,000 360 Total accounts payable, accrued expenses and other liabilities $29,717 $31,794 9. ASSET RETIREMENT OBLIGATIONS We have legal obligations associated with right-of-way contracts we hold and at our facilities whether owned or leased. Where we can reasonably estimate the asset retirement obligation, we accrue a liability based on an estimate of the timing and amount of settlement. We record changes in these estimates based on changes in the expected amount and timing of payments to settle our obligations. 43 The following table presents the changes in the net asset retirement obligations for the years ended December 31, 2012 and 2011 (In thousands): Net asset retirement obligation at January 1 Liabilities incurred Acquisitions Accretion expense Changes in estimate December 31, 2012 2011 $11,545 425 1,358 696 — $ 9,877 140 1,744 508 (724) Net asset retirement obligation at December 31 $14,024 $11,545 We did not have any material assets that were legally restricted for use in settling asset retirement obligations as of December 31, 2012 and 2011. 10. COMMITMENTS AND CONTINGENT LIABILITIES Legal Proceedings From time to time, we are party to certain legal or administrative proceedings that arise in the ordinary course and are incidental to our business. There are currently no such pending proceedings to which we are a party that our management believes will have a material adverse effect on our results of operations, cash flows or financial condition. However, future events or circumstances, currently unknown to management, will determine whether the resolution of any litigation or claims will ultimately have a material effect on our results of operations, cash flows or financial condition in any future reporting periods. As of December 31, 2012, we had less than $0.1 million accrued for our legal proceedings. Regulatory Compliance In the ordinary course of our business, we are subject to various laws and regulations. In the opinion of our management, compliance with current laws and regulations will not have a material effect on our results of operations, cash flows or financial condition. Environmental Compliance Our operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. 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, 2012, we had accrued approximately $0.2 million for environmental matters, which is based on our undiscounted estimate of amounts we will spend on environmental compliance and remediation. We estimate that our potential liability for reasonably possible outcomes related to our environmental exposures could range from approximately $0.2 million to $0.3 million. We had no accruals for environmental matters at December 31, 2011. Commitments and Purchase Obligations Capital Leases. We have a compressor, treating facility and auto leases which are accounted for as capital leases. The terms of the agreements vary from 2013 until 2016. We recorded amortization of expense of approximately $3 million and $2 million for the years ended December 31, 2012 and 2011. We had no capital leases during 2010. 44 Future minimum lease payments related to our capital leases at December 31, 2012 are as follows (In thousands): 2013 2014 2015 2016 Total payments Imputed interest Present value of future payments $4,020 2,269 866 219 7,374 (351) $7,023 Operating Leases. We maintain operating leases in the ordinary course of our business activities. These leases include those for office buildings and other operating facilities and equipment. The terms of the agreements vary from 2013 until 2032. Future minimum annual rental commitments under our operating leases at December 31, 2012, were as follows (In thousands): 2013 2014 2015 2016 2017 Thereafter Total $ 936 687 439 114 47 15 $2,238 Rental expense was approximately $7 million, $8 million and $1 million for the years ended December 31, 2012, 2011 and 2010. Purchase Commitments. At December 31, 2012, we had capital commitments of approximately $11.6 million to purchase equipment related to our capital projects. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures. Other. In connection with the Antero Acquisition, we agreed to pay Antero conditional consideration in the form of potential additional cash payments of up to $40 million, depending on the achievement of certain defined average annual production levels achieved during 2012, 2013 and 2014. During 2012, Antero did not meet the annual production level to earn additional payments. Based on actual volumes received in 2012 and expected volumes, we do not believe that it is probable that Antero will be able to achieve these average annual production levels in 2013 and 2014. 11. INCOME TAXES No provision for federal or state income taxes is included in our results of operations as such income is taxable directly to the partners. Accordingly, each partner is responsible for its share of federal and state income tax. Net earnings for financial statement purposes may differ significantly from taxable income reportable to each partner as a result of differences between the tax basis and financial reporting basis of assets and liabilities. We are responsible for our portion of the Texas Margin tax that is included in Crestwood Holdings’ consolidated Texas franchise tax return. Our current tax liability will be assessed based on 0.7% of the gross revenue apportioned to Texas. The margin tax qualifies as an income tax under GAAP, which requires us to 45 recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax. For the years ended December 31, 2012, 2011 and 2010, there were no temporary differences recognized in our consolidated statements of income. Prior to the closing of the Crestwood Transaction on October 1, 2010, our activity was included in Quicksilver’s Texas Franchise tax combined report. As a result, we had a deferred tax liability which represented the change in the tax basis and financial reporting basis of our assets and liabilities. During 2010, we reversed a deferred tax liability of $0.8 million as a result of the change in organization structure with the Crestwood Transaction. Uncertain Tax Positions. We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our consolidated financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Tax positions with respect to tax at the partnership level deemed not to meet the more likely than not threshold would be recorded as a tax benefit or expense in the current year. We believe that there are no uncertain tax positions that would impact our operations for the years ended December 31, 2012, 2011 and 2010 and that no provision for income tax is required for these consolidated financial statements. However, our conclusions regarding the evaluation are subject to review and may change based on factors including, but not limited to, ongoing analyses of tax laws, regulations and interpretations thereof. 12. EQUITY PLAN Awards of phantom and restricted units have been granted under our Fourth Amended and Restated 2007 Equity Plan (2007 Equity Plan). The following table summarizes information regarding phantom and restricted unit activity: Unvested - December 31, 2010 Vested - phantom units Granted - phantom units Granted - restricted units Cancelled - phantom units Unvested - December 31, 2011 Vested - phantom units Vested - restricted units Granted - phantom units Granted - restricted units Canceled - phantom units Unvested - December 31, 2012 Payable In Cash Payable In Units Weighted- Average Grant Date Fair Value $ — — 26.77 — 29.31 $26.40 26.46 — — — 25.63 $26.45 Weighted- Average Grant Date Fair Value $27.11 — 27.56 27.70 27.16 $27.22 27.21 27.53 29.90 25.67 28.30 $28.35 Units 121,526 — 19,411 10,000 (22,142) 128,795 (40,929) (4,682) 126,246 37,500 (24,938) 221,992 Units — — 15,294 — (1,948) 13,346 (4,267) — — — (767) 8,312 As of December 31, 2012 and 2011, we had total unamortized compensation expense of approximately $3 million and $2 million related to phantom and restricted units, which we expect will be amortized over three years (the original vesting period of these instruments), except for grants to non-employee directors of our General Partner which vest over one year. We recognized compensation expense of approximately $2 million and $1 million for the years ended December 31, 2012 and 2011, included in operating expenses on our consolidated statements of income. We granted phantom and restricted units with a grant date fair value of approximately $5 million and $0.8 million for the years ended December 31, 2012 and 2011. As of December 31, 2012 and 2011, we had 505,791 units and 633,211 units available for issuance under the 2007 Equity Plan. 46 Under the 2007 Equity Plan, participants who have been granted restricted units may elect to have us withhold common units to satisfy minimum statutory tax withholding obligations arising in connection with the vesting of non-vested common units. Any such common units withheld are returned to the 2007 Equity Plan on the applicable vesting dates, which correspond to the times at which income is recognized by the employee. When we withhold these common units, we are required to remit to the appropriate taxing authorities the fair value of the units withheld as of the vesting date. The number of units withheld is determined based on the closing price per common unit as reported on the NYSE on such dates. For the year ended December 31, 2012, we withheld 1,405 common units to satisfy employee tax withholding obligations. The withholding of common units by us could be deemed a purchase of the common units. There were no common units withheld to satisfy employee tax withholding obligations for the years ended December 31, 2011 and 2010. 13. TRANSACTIONS WITH RELATED PARTIES Affiliate Revenues and Expenses Our General Partner is owned by Crestwood Holdings. The affiliates of Crestwood Holdings and its owners are considered our related parties, including Sabine Oil and Gas LLC, and Mountaineer Keystone, LLC. In addition, under the agreements governing the Crestwood Transaction, 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 or such time as Quicksilver generates less than 50% of our consolidated revenue in any fiscal year. As such, Quicksilver, qualifies as a related party. We enter into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including gas gathering and processing services under long-term contracts, product purchases and various operating agreements. We do not have any employees. We are managed and operated by the directors and officers of our General Partner. We have an omnibus agreement with Crestwood Holdings and our General Partner under which we reimburse Crestwood Holdings for the provision of various general and administrative services for our benefit and for direct expenses incurred by Crestwood Holdings on our behalf. Crestwood Holdings bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. Prior to the closing of the Crestwood Transaction, employees of Quicksilver provided general and administrative services for our benefit. The allocations from Crestwood Holdings and Quicksilver were based on the estimated level of effort devoted to our operations. The table below shows overall revenues, expenses and reimbursements from our affiliates for the years ended December 31, 2012, 2011 and 2010 (In millions): Operating revenues Operating expenses Reimbursements of operating expenses (1) Amount was less than $1 million. Distributions Year Ended December 31, 2012 2011 2010 $114 35 1 $131 18 2 $105 21 — (1) Prior to Quicksilver’s sale of us to Crestwood Holdings on October 1, 2010, we paid cash distributions to Quicksilver in 2010 of approximately $80 million, including the conversion of the Subordinated Note Payable to common units for approximately $50 million. 47 14. PARTNERS’ CAPITAL During 2012 and 2011, we completed public offerings of common units, representing limited partner interests. The net proceeds from these offerings were used to reduce indebtedness under our Credit Facility and to fund our acquisitions. In April 2011, we issued Class C units, representing limited partner interests, in a private placement offering. The net proceeds from the April 2011 offering were used to finance a portion of our Frontier Gas Acquisition. The Class C units will convert into common units on a one-for-one basis on the second anniversary of the date of issuance. The table below presents our common unit and Class C unit issuances during 2012 and 2011 (In millions, except units and per unit data): Issuance Date April 1, 2011 May 4, 2011 January 13, 2012 July 25, 2012 Units 6,243,000(2) 1,800,000 3,500,000 4,600,000(3) Per Unit Gross Price Per Unit Net Price (1) Net Proceeds $24.50 $30.65 $30.73 $26.00 $ — $29.75 $29.50 $24.97 $153 53 103 115 (1) Price is net of underwriting discounts. (2) Represents Class C units. (3) Includes 600,000 units that were issued in August 2012. During 2012, our General Partner made additional capital contributions of approximately $6 million in exchange for the issuance of an additional 215,722 general partner units. During 2011, our General Partner made an additional capital contribution of approximately $9 million in exchange for the issuance of an additional 293,948 general partner units. In January 2013, we issued 6,190,469 Class D units, representing limited partner interests in us, to Crestwood Holdings in connection with our acquisition of Crestwood Holdings’ 65% membership interest in CMM. Our Class D units are similar in certain respects to our existing common units and Class C units, except that we have the option to pay distributions to our Class D unitholders with cash or by issuing additional Paid-In- Kind Class D units based upon the volume weighted-average price of our common units for the 10 trading days immediately preceding the date the distribution is declared. In March 2014, our outstanding Class D units will convert to common units. 15. SEGMENT INFORMATION Our operations include four reportable operating segments. These operating segments reflect the way we internally report the financial information used to make decisions and allocate resources in connection with our operations. We evaluate the performance of our operating segments based on EBITDA, which represents operating income plus, depreciation, amortization and accretion expense. Our reportable segments reflect the primary geographic areas in which we operate and consist of Barnett, Fayetteville, Granite Wash and Marcellus, all of which are located within the United States. Our reportable segments are engaged in the gathering, processing, treating, compression, transportation and sales of natural gas and delivery of NGLs. Our Other operating segment consists of those operating segments or reporting units that did not meet quantitative reporting thresholds. As of December 31, 2012, we managed 849 miles of natural gas gathering pipelines and approximately 259,000 hp of compression equipment. For the years ended December 31, 2012, 2011 and 2010, one of our customers in the Barnett segment, which is a related party, accounted for 47%, 64% and 93% of our total revenues. In addition, in our Fayetteville and Marcellus segments, one customer in each respective segment accounted for 11% of our total revenues for the year ended December 31, 2012. 48 The following table is a reconciliation of Net Income to EBITDA (In thousands): Net income Add: Interest and debt expense Income tax expense (benefit) Depreciation, amortization and accretion expense EBITDA For the Year Ended December 31, 2012 2011 2010 $ 38,889 $ 45,003 $34,872 35,765 1,206 51,908 27,617 1,251 33,812 13,550 (550) 22,359 $127,768 $107,683 $70,231 The following tables reflect our segment results as of and for the years ended December 31, 2012, 2011 and 2010 (In thousands): Year Ended December 31, 2012 Barnett (1) Fayetteville Granite Wash Marcellus (2) Other Corporate Total Operating revenues Operating revenues - related party Product purchases Product purchases - related party Operations and maintenance expense General and administrative expense $ 20,396 $ 27,498 $39,450 $ 25,502 $12,874 $ — $ 125,720 113,743 23,853 15,152 43,108 29,582 — — — — — 29,582 1,106 — 523 20,543 — 15,152 2,250 — 112,637 125 — 26,881 — — — — 2,491 — — 2,662 — 2,949 8,537 — EBITDA $106,027 $ 18,438 $ 2,611 $ 23,011 $ 7,263 $(29,582) $ 127,768 Goodwill Total assets Capital expenditures $ — $ 76,767 $14,211 $ — $ 4,053 $ — $ 95,031 $618,647 $300,593 $80,876 $505,816 $81,862 $ 22,675 $1,610,469 52,572 $ 13,903 $ 10,954 $ 4,787 $ 17,079 $ 4,797 $ 1,052 $ (1) (2) Includes four months of operating income from the Devon Acquisition, from August 24, 2012 to December 31, 2012, subsequent to acquisition. Includes nine months of operating income from the Antero Acquisition, from March 26, 2012 to December 31, 2012, subsequent to acquisition. Operating revenues Operating revenues - related party Product purchases Operations and maintenance expense General and administrative expense Gain from exchange of property, Barnett Fayetteville (1) $ 8,859 131,225 — 25,147 — $ 20,800 — 1,302 8,992 — Year Ended December 31, 2011 Granite Wash (1) Marcellus Other (2) (3) Corporate Total $38,213 — — 33,245 — 1,499 — — $— $ 6,723 $ — $ — 4,240 665 — — — — 24,153 — 74,595 131,225 38,787 36,303 24,153 plant and equipment — — — — — 1,106 1,106 EBITDA $114,937 $ 10,506 $ 3,469 $— $ 1,818 $(23,047) $ 107,683 Goodwill Total assets Capital expenditures $ — $ 76,767 $300,338 $545,656 $ 17,757 $ 19,999 $16,861 $77,313 $ 7,960 $— $ — $ — $ 93,628 $— $85,307 $ 18,278 $1,026,892 48,405 $— $ 2,041 $ 648 $ (1) Includes nine months of operating income for Fayetteville and Granite Wash, from April 1, 2011 to December 31, 2011, subsequent to acquisition. 49 (2) (3) Includes approximately eleven months of operating income for Las Animas System, from February 16, 2011 to December 31, 2011, subsequent to acquisition. Includes two months of operating income for Sabine System, from November 1, 2011 to December 31, 2011, subsequent to acquisition. Year Ended December 31, 2010 Barnett Fayetteville Granite Wash Marcellus Other Corporate Operating revenues Operating revenues - related party Operations and maintenance expense General and administrative expense EBITDA Total assets Capital expenditures $ 8,355 105,235 25,702 — $ 87,888 $557,163 $ 69,069 $— — — — $— $— $— $— — — — $— $— $— $— — — — $— $— $— $— $ — $ — — — — — 17,657 Total 8,355 105,235 25,702 17,657 $— $(17,657) $ 70,231 $— $ 13,464 $570,627 $— $ — $ 69,069 16. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS CMLP’s (Issuer) Credit Facility and Senior Notes are fully and unconditionally guaranteed, jointly and severally, by our present and future direct and indirect 100% owned subsidiaries (the Guarantor Subsidiaries), except for CMM and its consolidated subsidiaries (the Non-Guarantor Subsidiaries). The following reflects condensed consolidating financial information of the Issuer, Guarantor Subsidiaries, Non-Guarantor Subsidiaries, eliminating entries to combine the entities and the consolidated results of CMLP as of and for the year ended December 31, 2012. We have not reflected condensed consolidating financial information as of and for the year ended December 31, 2011 or 2010 because CMM was formed during the first quarter of 2012 and, prior to CMM’s formation, all of CMLP’s 100% owned subsidiaries fully and unconditionally guaranteed CMLP’s Credit Facility and Senior Notes and CMLP had no independent assets or operations. Operating revenues Operating expenses Operating income (loss) Interest and debt expense Income(loss) before income tax Income tax expense Income before earnings from consolidated subsidiaries Earnings from consolidated subsidiaries Net income (loss) General partner’s interest in net income For the Year Ended December 31, 2012 Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated $ — $213,961 150,631 607 (In thousands) $25,502 12,365 $ — — $239,463 163,603 (607) (33,388) (33,995) — (33,995) 72,884 38,889 22,218 63,330 (230) 63,100 1,206 61,894 — 61,894 — 13,137 (2,147) 10,990 — 10,990 — 10,990 — — — — — — (72,884) (72,884) — 75,860 (35,765) 40,095 1,206 38,889 — 38,889 22,218 Limited partner’s interest in net income $ 16,671 $ 61,894 $10,990 (72,884) $ 16,671 50 Current assets ASSETS Cash and cash equivalents Accounts receivable - related party Accounts receivable Insurance receivable Prepaid expenses and other Total current assets Investment in consolidated affiliates Property, plant and equipment - net Intangible assets - net Goodwill Deferred financing costs, net Other assets Total assets As of December 31, 2012 Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) $ 21 $ 366,405 608 — 584 367,618 1,041,935 8,519 — — 17,149 20 — 22,587 14,515 2,920 1,357 41,379 — 775,852 163,021 95,031 — 1,301 $ 90 — 6,513 — — 6,603 — 155,475 338,359 — 5,379 — $ — $ (365,237) — — — (365,237) (1,041,935) — — — 111 23,755 21,636 2,920 1,941 50,363 — 939,846 501,380 95,031 22,528 1,321 $1,435,241 $1,076,584 $505,816 $(1,407,172) $1,610,469 LIABILITIES AND PARTNERS’ CAPITAL/MEMBERS’ EQUITY Current liabilities Accrued additions to property, plant and equipment Capital leases Deferred revenue Accounts payable - related party Accounts payable, accrued expenses and other liabilities $ — $ 429 — 535 15,547 Total current liabilities Long-term debt Long-term capital leases Asset retirement obligations Partners’/members’ equity 16,511 558,161 960 — 859,609 3,829 3,433 — 367,682 11,876 386,820 — 2,201 13,188 674,375 $ 5,384 — 2,634 — 2,402 10,420 127,000 — 836 367,560 $ — $ — — (365,129) (108) (365,237) — — (1,041,935) 9,213 3,862 2,634 3,088 29,717 48,514 685,161 3,161 14,024 859,609 Total liabilities and partners’ capital/members’ equity $1,435,241 $1,076,584 $505,816 $(1,407,172) $1,610,469 51 For the Year Ended December 31, 2012 Issuer Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (23,613) $112,880 (In thousands) $ 16,645 $ (3,847) $ 102,065 Investing activities: Acquisitions, net of cash acquired Capital expenditures Acquisition of interests in CMM Change in advances to affiliates, net Capital distribution from consolidated affiliate Proceeds from sale of property, plant and equipment (87,247) (1,052) (131,250) 75,825 2,604 — — (34,441) — — — 20 Net cash provided by (used in) investing activities (141,120) (34,421) (476,718) (17,079) — — — — (493,797) — — 131,250 (75,825) (2,604) — (563,965) (52,572) — — — 20 52,821 (616,517) Financing activities: Proceeds from issuance of senior notes Proceeds from revolving credit facility Repayment of revolving credit facility Payment of Tristate Acquisition deferred payment Payments on capital leases Deferred financing costs paid Proceeds from issuance of common units, net Contributions received Distributions paid Change in advances from affiliates, net Taxes paid for equity-based compensation vesting 151,500 411,700 (517,500) (7,839) (359) (4,994) 217,483 5,930 (91,558) — (406) — — — — (2,634) — — (75,825) Net cash provided by (used in) financing activities 163,957 (78,459) Change in cash and cash equivalents Cash and cash equivalents at beginning of period (776) 797 — — Cash and cash equivalents at end of period $ 21 $ — $ — 143,500 (16,500) — — (6,328) — 375,000 (18,430) — — 477,242 90 — 90 — — — — — — (131,250) 6,451 75,825 151,500 555,200 (534,000) (7,839) (2,993) (11,322) 217,483 249,680 (103,537) — (406) (48,974) 513,766 — — — $ (686) 797 111 $ 52 Supplemental Selected Quarterly Financial Information (Unaudited) Financial information by quarter is summarized below (In thousands). 2012 Operating revenues Operating income Net income Basic income per unit: March 31 June 30 September 30 December 31 Quarters Ended $53,733 17,665 9,805 $55,229 15,862 6,624 $63,013 23,766 14,555 $67,488 18,567 7,905 Net income per limited partner unit $ 0.15 $ 0.06 $ 0.15 $ 0.01 Diluted income per unit: Net income per limited partner unit $ 0.15 $ 0.06 $ 0.15 $ 0.01 2011 Operating revenues Operating income Net income Basic income per unit: $32,380 12,604 9,376 $55,535 20,375 10,227 $58,615 20,505 13,058 $59,290 20,387 12,342 Net income per limited partner unit $ 0.27 $ 0.22 $ 0.27 $ 0.24 Diluted income per unit: Net income per limited partner unit $ 0.27 $ 0.22 $ 0.27 $ 0.24 53 [THIS PAGE INTENTIONALLY LEFT BLANK] [THIS PAGE INTENTIONALLY LEFT BLANK] [THIS PAGE INTENTIONALLY LEFT BLANK] [THIS PAGE INTENTIONALLY LEFT BLANK] Non-GAAP Reconciliation Crestwood Midstream Partners LP (Dollar amounts in thousands) Year ended December 31 Net income from continuing operations Loss from discontinued operations Net income Items impacting net income: Gain from exchange of property, plant and equipment Non-cash compensation (accelerated vesting) Significant transaction related expenses Non-cash interest expense (write-off of deferred financing costs) Interest expense (bridge loan fees) 2009 2010 2011 20121 $ 34,491 (1,992) 32,499 $ 34,872 – 34,872 $ 45,003 – 45,003 $ 38,889 – 38,889 – – – – – – 3,581 2,737 1,558 – (1,106) – 3,385 – 2,500 – – 4,697 370 – Adjusted net income $ 32,499 $ 42,748 $ 49,782 $ 43,956 Total revenues Product purchases Operations and maintenance expense General and administrative expense Other income Gain from exchange of property, plant and equipment $ 95,881 – (21,968) (9,676) 1 – $113,590 – (25,702) (17,657) – – EBITDA Gain from exchange of property, plant and equipment Non-cash compensation (accelerated vesting) Significant transaction related expenses Adjusted EBITDA Less: Depreciation, amortization and accretion expense Interest and debt expense Income tax expense (benefit) Gain from exchange of property, plant and equipment Non-cash compensation (accelerated vesting) Significant transaction related expenses 64,238 – – – 64,238 20,829 8,519 399 – – – 70,231 – 3,581 2,737 76,549 22,359 13,550 (550) – 3,581 2,737 $205,820 (38,787) (36,303) (24,153) – 1,106 107,683 (1,106) – 3,385 109,962 33,812 27,617 1,251 (1,106) – 3,385 $239,463 (39,005) (43,108) (29,582) – – 127,768 – – 4,697 132,465 51,908 35,765 1,206 – – 4,697 Net income from continuing operations $ 34,491 $ 34,872 $ 45,003 $ 38,889 Net income from continuing operations Depreciation, amortization and accretion expense Income tax expense (benefit) Amortization of deferred financing fees Non-cash equity compensation Maintenance capital expenditures Distributable cash flow Add: Gain from exchange of property, plant and equipment Add: Interest expense (bridge loan fees) Add: Significant transaction related expenses Add: Significant minimum volume deficiency payment $ 34,491 20,829 399 3,836 1,705 (10,000) 51,260 $ 34,872 22,359 (550) 4,961 5,522 (6,600) $ 45,003 33,812 1,251 3,473 916 (1,409) $ 38,889 51,908 1,206 5,455 1,877 (4,302) 60,564 83,046 95,033 – – – – – – 2,737 – (1,106) 2,500 3,385 – – – 4,697 5,352 Adjusted distributable cash flow $ 51,260 $ 63,301 $ 87,825 $105,082 1 Data for 2012 reflects updated financial and operating information filed with the Securities and Exchange Commission on Form 8-K on March 18, 2013. This information was required as a result of Crestwood Midstream Partners LP acquiring the remaining membership interests in Crestwood Marcellus Midstream LLC (CMM) on January 8, 2013. A copy of the Form 8-K is included with this report. Board of Directors Robert G. Phillips Chairman, President and CEO of Crestwood Gas Services GP LLC Alvin Bledsoe (1) Retired Partner, Pricewaterhouse-Coopers Director of SunCoke Energy, Inc. Timothy H. Day Managing Director, First Reserve Corporation Director of PBF Energy, Inc. Michael G. France Managing Director, First Reserve Corporation Director of Cobalt International Energy, Inc. Philip D. Gettig (2) Retired General Counsel, Union Pacific Fuels, Inc. Vanessa Gomez LaGatta Vice President and Treasurer, Quicksilver Resources Inc. Joel C. Lambert Vice President, Legal, First Reserve Corporation J. Hardy Murchison President, Encino Energy, LLC John W. Somerhalder II (3) Chairman, President and Chief Executive Officer AGL Resources Inc. (1) Chair of Audit Committee, member of Conflicts Committee (2) Chair of Conflicts Committee, member of Audit Committee (3) Member of Audit Committee and Conflicts Committee Investor Information Exchange Information Our common units are traded on the NYSE under the symbol “CMLP”. Additional Information For more information, please visit our website at www.crestwoodlp.com. Through our website, you may elect to receive news, SEC filings and other information. Transfer Agent For information regarding change of address or other matters concerning your units, please contact our transfer agent Computer- share, directly at: Computershare 250 Royall Street Canton, MA 02021 Phone: (888) 581-9370 www.computershare.com/investor Principal Executive Offices Crestwood Midstream Partners LP 700 Louisiana, Suite 2060 Houston, TX 77002 Phone: (832) 519-2200 Fax: (832) 519-2250 Crestwood Midstream Partners LP is managed by its General Partner, Crestwood Gas Services GP LLC, which is owned and managed by Crestwood Holdings Partners, LLC (Crestwood Holdings), a partnership formed in 2010 between First Reserve and the Crestwood management team. I C R E S T W O O D M D S T R E A M P A R T N E R S L P 2 0 1 2 A N N U A L R E P O R T