10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X]    Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2011

or

[  ]    Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                      to                     

Commission File No. 1-34831

Chesapeake Midstream Partners, L.P.

(Exact name of registrant as specified in its charter)

Delaware	80-0534394
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
900 N.W. 63rd Street
Oklahoma City, Oklahoma	73118
(Address of principal executive offices)	(Zip Code)

(405) 935-1500

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Units Representing Limited Partner Interests	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES [  ]      NO [X]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

YES [  ]      NO [X]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X]      NO [  ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES [X]      NO [  ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [X]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer [  ]    Accelerated Filer [X]    Non-accelerated Filer [  ]    Smaller Reporting Company [  ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES [  ]      NO [X]

The aggregate market value of our common units held by non-affiliates on June 30, 2011 was approximately $698.5 million.

As of February 22, 2012, there were 78,899,650 common units outstanding.

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

2011 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business		1
Item 1A.	Risk Factors		15
Item 1B.	Unresolved Staff Comments		43
Item 2.	Properties		43
Item 3.	Legal Proceedings		43
Item 4.	Mine Safety Disclosures		43
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		44
Item 6.	Selected Financial Data		46
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		48
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		74
Item 8.	Financial Statements and Supplementary Data		75
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		107
Item 9A.	Controls and Procedures		107
Item 9B.	Other Information		107
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		108
Item 11.	Executive Compensation		115
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		131
Item 13.	Certain Relationships and Related Transactions and Director Independence		133
Item 14.	Principal Accountant Fees and Services		152
PART IV
Item 15.	Exhibits and Financial Statement Schedules		153

Part I

ITEM 1. Business

Unless the context otherwise requires, references in this report to the “Partnership,” “we,” “our,” “us” or like terms, when used in a historical context, refer to the financial results of Chesapeake Midstream Partners, L.L.C. from its inception on September 30, 2009 through the closing date of our initial public offering (“IPO”) on August 3, 2010 and to Chesapeake Midstream Partners, L.P. (NYSE: CHKM) and its subsidiaries thereafter. Our “predecessor” refers to Chesapeake Midstream Development, L.P., which held substantially all of our assets as well as other midstream assets prior to September 30, 2009. “Chesapeake” refers to Chesapeake Energy Corporation (NYSE: CHK), and, where the context requires, its subsidiaries, and “GIP” refers to Global Infrastructure Partners—A, L.P., and affiliated funds managed by Global Infrastructure Management, LLC, and certain of their respective subsidiaries and affiliates. “Chesapeake Midstream Ventures” refers to Chesapeake Midstream Ventures, L.L.C., the sole member of our general partner. “Total”, when discussing the upstream joint venture with Chesapeake, refers to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (NYSE: TOT, FP: FP), and when discussing our gas gathering agreement and related matters, refers to Total E&P USA, Inc. and Total Gas & Power North America, Inc., a wholly owned subsidiary of Total S.A.

General

We are a growth-oriented publicly-traded Delaware limited partnership formed by Chesapeake and GIP to own, operate, develop and acquire natural gas, natural gas liquids and oil gathering systems and other midstream energy assets. We are principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. The following diagram illustrates our area of focus in the natural gas value chain:

We provide gathering, treating and compression services to Chesapeake, Total, and other leading producers under long-term, fixed-fee contracts. Our gathering systems operate in our Barnett Shale region in north-central Texas, our Haynesville Shale region in northwest Louisiana, our Marcellus Shale region in Pennsylvania and West Virginia, and our Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian Basins. We generate the majority of our operating income in our Barnett Shale region, where we service approximately 2,219 wells in the core of the prolific Barnett Shale. Our Springridge gathering system services approximately 220 wells in one of the core areas of the Haynesville Shale. Through our recently acquired ownership interest in 10 Marcellus gathering systems, we service approximately 281 wells in the Marcellus Shale. In our Mid-Continent region, we have an enhanced focus on the unconventional resources located in the Colony Granite Wash and Texas Panhandle Granite Wash plays of the Anadarko Basin. In total, our systems consist of approximately 3,629 miles of gathering pipelines, servicing approximately 4,965 natural gas wells prior to the Appalachia Midstream Services, L.L.C. (“Appalachia Midstream”) acquisition on December 29, 2011. For the year ended December 31, 2011, our assets gathered approximately 2.2 billion cubic feet (“Bcf”) of natural gas per day. On December 29, 2011, we acquired 100 percent of

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Appalachia Midstream, which operates 100 percent of and owns an approximate average 47 percent interest in 10 gas gathering systems in the Marcellus Shale. The Marcellus gathering systems generate gross throughput of just over 1.0 Bcf of natural gas per day (approximately 470 million cubic feet (“Mmcf”) per day net to us) in Pennsylvania and West Virginia.

Our gas gathering systems primarily collect natural gas from unconventional resource plays, a growing source of U.S. natural gas supply that is generally characterized by low finding and development costs compared to conventional resource plays. These systems were historically operated by Chesapeake and are integral to Chesapeake’s operations in our Barnett Shale, Haynesville Shale, Marcellus Shale and Mid-Continent regions.

We generate substantially all of our revenues through long-term, fixed-fee natural gas gathering, treating and compression contracts that limit our direct commodity price exposure. We are party to (i) a 20-year gas gathering agreement with respect to the Barnett Shale and the Mid-Continent regions with certain subsidiaries of Chesapeake that was entered into in connection with the creation of our predecessor in September 2009, (ii) a 20-year gas gathering agreement with respect to the Barnett Shale with Total that was entered into in connection with an upstream joint venture transaction between Chesapeake and Total in January 2010, (iii) a 10-year gas gathering agreement with certain subsidiaries of Chesapeake that was entered into concurrent with the closing of our acquisition of the Springridge gas gathering system in the Haynesville Shale in December 2010 and (iv) through Appalachia Midstream, 15-year gas gathering agreements with certain subsidiaries of Chesapeake, Statoil ASA (NYSE: STO) (“Statoil”), Anadarko Petroleum Corporation (NYSE: APC) (“Anadarko”), Epsilon Energy Ltd. (TSE: EPS) (“Epsilon”), Mitsui & Co., Ltd. (TYO: 8031) (“Mitsui”) and Chief Oil & Gas LLC (“Chief”) that we acquired in connection with our acquisition of Appalachia Midstream in December 2011. Pursuant to these gas gathering agreements, we have been provided with extensive acreage dedications in our operating regions. These agreements generally contain the following terms:

• opportunity to connect natural gas drilling pads and wells of the counterparties to these agreements within our acreage dedications to our gathering systems in all of our regions;

• minimum volume commitments for 10 years in our Barnett Shale region and for three years in our Haynesville Shale region, which mitigate throughput volume variability;

• fee redetermination mechanisms, which are designed to support a return on invested capital and allow our gathering rates to be adjusted, subject to specified caps in certain cases, to account for variability in revenues, capital expenditures and compression and other expenses; and

• price escalators in our Barnett Shale, Haynesville Shale and Mid-Continent regions, which annually increase our gathering rates.

Information About Us

Our principal executive offices are located at 900 N.W. 63rd Street, Oklahoma City, Oklahoma 73118, and our telephone number is (405) 935-1500. Our website is located at www.chkm.com. We make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (“SEC”), free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent press releases.

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Initial Public Offering

On August 3, 2010, we completed our IPO of 24,437,500 common units (including 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option on August 3, 2010) at a price of $21.00 per unit. Our common units are listed on the New York Stock Exchange (the “NYSE”) under the symbol “CHKM”.

We received gross offering proceeds of approximately $513.2 million less approximately $38.6 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of the contribution agreement, we distributed the approximate $62.4 million of net proceeds from the exercise of the over-allotment option to GIP on August 3, 2010. Upon completion of the IPO, Chesapeake and GIP conveyed to us a 100 percent membership interest in Chesapeake MLP Operating, L.L.C., which owned all of our assets since September 2009.

Acquisitions

Marcellus Acquisition

On December 29, 2011, we acquired from Chesapeake Midstream Development, L.P. (“CMD”), a wholly owned subsidiary of Chesapeake, and certain of its affiliates, all of the issued and outstanding common units of Appalachia Midstream for total consideration, which is subject to a customary post-closing working capital adjustment, of $879.3 million, consisting of 9,791,605 common units and $600.0 million in cash that was financed with a draw on our revolving credit facility. Through the acquisition of Appalachia Midstream, we operate 100 percent of and own an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 231 miles of gas gathering pipeline in the Marcellus Shale. The remaining 53 percent interest in these assets is owned primarily by Statoil, Anadarko, Epsilon and Mitsui. Gross throughput for these assets at December 31, 2011, was just over 1.0 Bcf per day (approximately 470 Mmcf per day net to us). Appalachia Midstream operates the assets under 15-year fixed fee gathering agreements. The 100 percent fixed-fee gathering agreements include significant acreage dedications and annual fee redeterminations. In addition, CMD has committed to pay us quarterly any shortfall between the actual EBITDA from these assets and specified quarterly targets, with the quarterly targets adding to a total of $100 million in 2012 and $150 million in 2013.

The results of operations presented and discussed in this annual report include results of operations from Appalachia Midstream for the two-day period from closing of the acquisition on December 29, 2011, through December 31, 2011.

Haynesville Acquisition

On December 21, 2010, we acquired the Springridge gathering system and related facilities from CMD for $500.0 million. The Springridge gathering system consisted of 226 miles of gathering pipeline primarily located in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, we entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication, annual fee redetermination and a three-year minimum volume commitment.

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Our Assets and Areas of Operation

Prior to the closing of the Marcellus acquisition, we generated approximately 64 percent of our revenues from our gathering systems in our Barnett Shale region. The following table summarizes average daily throughput and assets by region as of and for the year ended December 31, 2011:

Region	Location (State(s))	Average Throughput (Bcf/d)		Approximate Length (Miles)		Approximate Number of Wells Serviced		Gas Compression (Horsepower)(1)
Barnett Shale	TX		1.083		882		2,219		159,810
Haynesville Shale	LA		0.541		260		220		23,745
Mid-Continent	TX, OK, KS, AR		0.552		2,487		2,526		94,621
Total(2)			2.176		3,629		4,965		278,176

(1) Substantially all of our gas compression is provided by compression equipment leased from a subsidiary of Chesapeake.

(2) Excludes Marcellus assets acquired on December 29, 2011 due to immaterial contribution to 2011 results.

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Barnett Shale Region

General.    Our gathering systems in our Barnett Shale region are primarily located in Tarrant, Johnson and Dallas counties in Texas in the Core and Tier 1 areas of the Barnett Shale and currently consist of 25 interconnected gathering systems and 882 miles of pipeline. The Core and Tier 1 areas are characterized by thicker natural gas bearing geological zones, which results in higher initial production rates. Typically, gas produced in Core and Tier 1 areas is characterized as “lean” and needs little to no treatment to remove contaminants.

Our assets in the Barnett region have been designed and developed to accommodate their urban setting in and around the greater Dallas/Fort Worth, Texas metropolitan area. Average throughput on our Barnett Shale gathering system for the year ended December 31, 2011, was 1.083 Bcf per day. We connect our gathering systems to receipt points that are either at the individual wellhead or at central receipt points into which production from multiple wells are gathered. Due to Chesapeake’s practice of drilling multiple wells on an individual drilling pad, a significant number of our receipt points in the Barnett Shale collect production from multiple producing wells. Our Barnett Shale system has pipeline diameters ranging from four-inch well connection lines to 24-inch major trunk lines and is connected to 104 compressor units providing a combined 159,810 horsepower of compression.

Delivery Points.    Our Barnett Shale gathering system is connected to the following downstream transportation pipelines:

• Atmos Pipeline Texas—natural gas delivered into this pipeline system serves the greater Dallas/Fort Worth metropolitan area and south, east and west Texas markets at the Katy, Carthage and Waha hubs;

• Energy Transfer Pipeline Texas—natural gas delivered into this pipeline system serves the greater Dallas/Fort Worth metropolitan area and southeastern and northeastern U.S. markets supplied by the Midcontinent Express Pipeline, Centerpoint CP Expansion Pipeline and Gulf South 42” Expansion Pipeline; and

• Enterprise Texas Pipeline—natural gas delivered into this pipeline system serves the greater Dallas/Fort Worth metropolitan area and southeastern and northeastern U.S. markets supplied by the Gulf Crossing Pipeline.

Haynesville Shale Region

General.    Our Springridge gas gathering system in the Haynesville Shale region is primarily located in Caddo and DeSoto Parishes, Louisiana, in one of the core areas of the Haynesville Shale and currently consists of 260 miles of pipeline. The core areas are characterized by thicker natural gas bearing geological zones, which results in higher initial production rates. Haynesville Shale gas production is characterized as “lean” and typically needs to be treated to remove small amounts of carbon dioxide and hydrogen sulfide.

A portion of our assets in the Springridge gathering system have been designed and developed to accommodate their urban setting in and around the city of Shreveport, Louisiana. Average throughput on our Springridge gathering system for the year ended December 31, 2011, was 0.541 Bcf per day. We connect our gathering systems to receipt points that are either at the individual wellhead or at central receipt points into which production from multiple wells is gathered. Chesapeake’s pad drilling concept is used extensively around the Springridge gathering system. Our Springridge gathering system has pipeline diameters ranging from four-inch well connection lines to a 24-inch major trunk line and is connected to 11 compressor units providing a combined 23,745 horsepower of compression.

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Delivery Points.    Our Springridge gathering system is connected to the following downstream transportation pipelines:

• Centerpoint Energy Gas Transmission—natural gas delivered into this 42” diameter pipeline can be received at the Carthage, Texas, and Perryville, Louisiana hubs, and is connected to numerous interstate pipelines;

• ETC Tiger Pipeline—natural gas delivered into this 42” diameter pipeline can also be received at the Carthage and Perryville hubs. ETC Tiger Pipeline provides deliveries to seven interstate pipelines and one intrastate pipeline for ultimate delivery to the Midwest and Northeast; and

• Texas Gas Transmission Pipeline—natural gas delivered into this pipeline can move to on-system markets in the Midwest and to off-system markets in the Northeast via interconnections with third-party pipelines or it can be received at the Carthage hub in East Texas.

Marcellus Shale Region

General.    Through Appalachia Midstream, we operate 100 percent of and own an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 231 miles of gathering pipeline in the Marcellus Shale region located in northern Pennsylvania, southwestern Pennsylvania and the northwestern panhandle of West Virginia, in core areas of the Marcellus Shale. The core areas are characterized by thicker natural gas bearing geological zones, which results in higher initial production rates. Marcellus Shale gas production can be characterized as “lean” dry gas or wet gas depending on its location. In general, the gas in the northern Marcellus Shale is lean and typically requires little to no treatment to remove contaminants. Southern Marcellus Shale gas is wet and typically requires treatment and processing from third parties to remove natural gas liquids (“NGLs”) prior to delivery into the pipeline grid. Gross throughput for these assets at December 31, 2011 was just over 1.0 Bcf per day (approximately 470 Mmcf per day net to us). These gathering systems are connected to receipt points that are either at the individual wellhead or at central receipt points into which production from multiple wells are gathered.

Delivery Points.    Our Marcellus gathering system is connected to the following downstream transportation pipelines:

• Caiman Energy—rich natural gas is delivered into a 16” pipeline and delivered to the Caiman Energy Fort Beeler processing plant where the liquids are extracted from the rich gas stream. The natural gas is then delivered into the TETCo interstate pipeline for ultimate delivery to the Northeast regions of the U.S.;

• Central New York Oil & Gas—natural gas delivered into this 30” diameter pipeline (South Lateral of Stagecoach Storage) can be delivered to Stagecoach Storage, Millennium Pipeline, or Tennessee Gas Pipeline’s Line 300. Together with Inergy’s proposed Marc I Pipeline, gas delivered into this pipeline will be able to be wheeled / transported bi-directionally approximately 75 miles between the Millennium Pipeline and Transco’s Leidy Line and all points between;

• Columbia Gas Transmission—lean natural gas is delivered into two 36” interstate pipelines for ultimate delivery to the Mid-Atlantic and Northeast regions of the U.S.;

• MarkWest—rich natural gas is delivered into a MarkWest pipeline for delivery to the MarkWest Houston processing plant where the liquids are extracted from the rich gas stream. The natural gas is then delivered into the TCO and TETCo interstate pipelines for ultimate delivery to the Mid-Atlantic and Northeast regions of the U.S. The extracted liquid is then delivered to the MarkWest fractionation plant in Houston, Pennsylvania;

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• NiSource Midstream—rich natural gas is delivered into a 20” diameter pipeline and delivered to the MarkWest Majorsville processing plant where the liquids are extracted from the rich gas stream. The natural gas is then delivered into the TCO and TETCo interstate pipelines for ultimate delivery to the Mid-Atlantic and Northeast regions of the U.S. The extracted liquid is then delivered to the MarkWest fractionation plant in Houston, Pennsylvania; and

• Tennessee Gas Pipeline—natural gas delivered into this looped 30” diameter pipeline (TGP Line 300) at three different locations can be received in the Northeast at points along the 300 Line path, various interconnections with other pipelines in northern New Jersey, as well as an existing delivery point in White Plains, New York.

Mid-Continent Region

Our Mid-Continent gathering systems extend across portions of Oklahoma, Texas (excluding the Barnett Shale), Arkansas (excluding the Fayetteville Shale) and Kansas. Included in our Mid-Continent region are three treating facilities located in Beckham and Grady Counties, Oklahoma, and Reeves County, Texas, that are designed to remove contaminants from the natural gas stream.

Anadarko Basin and Northwest Oklahoma

General.    Our assets within the Anadarko Basin and Northwest Oklahoma are located in northwestern Oklahoma and the northeastern portion of the Texas Panhandle and consist of approximately 1,566 miles of pipeline. Our Anadarko Basin and Northwest Oklahoma region gathering systems had an average throughput for the year ended December 31, 2011 of 0.375 Bcf per day. These systems are connected to 63 compressor units providing a combined 56,564 horsepower of compression.

Within the Anadarko Basin, we are primarily focused on servicing Chesapeake’s production from the Colony Granite Wash and Texas Panhandle Granite Wash plays. Natural gas production from these areas of the Anadarko Basin typically contains a significant amount of NGLs and requires processing prior to delivery to end-markets. In addition, we operate an amine treater with sulfur removal capabilities at our Mayfield facility in Beckham County, Oklahoma. Our Mayfield gathering and treating system primarily gathers Deep Springer natural gas production and treats the natural gas to remove carbon dioxide and hydrogen sulfide to meet the quality specifications of downstream transportation pipelines.

Delivery Points.    Our Anadarko Basin and Northwest Oklahoma systems are connected to a significant majority of the major transportation pipelines transporting natural gas out of the region, including pipelines owned by Enbridge and Atlas Pipelines, as well as local market pipelines such as those owned by Enogex. These pipelines provide access to Midwest and northeastern U.S. markets as well as intrastate markets.

Permian Basin

General.    Our Permian Basin assets are located in west Texas and consist of approximately 350 miles of pipeline across the Permian and Delaware basins. Average throughput on our gathering systems for the year ended December 31, 2011, was 0.070 Bcf per day. The systems have pipeline diameters ranging from four inches to 16 inches and are connected to 20 compressor units providing a combined 17,320 horsepower of compression.

Delivery Points.    Our Permian Basin gathering systems are connected to pipelines in the area owned by Southern Union, Enterprise, West Texas Gas, CDP Midstream and Regency. Natural gas delivered into these transportation pipelines is re-delivered into the Waha hub and El Paso Gas

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Transmission. The Waha hub serves the Texas intrastate electric power plants and heating market, as well as the Houston Ship Channel chemical and refining markets. El Paso Gas Transmission serves western U.S. markets.

Other Mid-Continent Regions

Our other Mid-Continent region assets consist of systems in the Ardmore Basin in Oklahoma, the Arkoma Basin in eastern Oklahoma and western Arkansas and the East Texas and Gulf Coast regions of Texas. The other Mid-Continent assets include approximately 571 miles of pipeline. These gathering systems are generally localized systems gathering specific production for re-delivery into established pipeline markets. Average throughput on these gathering systems for the year ended December 31, 2011 was 0.107 Bcf per day. The systems have pipeline diameters ranging from four inches to 24 inches and are connected to 39 compressor units providing a combined 20,737 horsepower of compression.

General Trends

Since 2010, we have observed a shift in drilling activity by Chesapeake and other producers from the dry gas shale plays such as the Barnett Shale and Haynesville Shale to liquids-rich plays such as the Marcellus South and Mid-Continent regions. We believe this trend is likely to continue for the foreseeable future. Any decrease in production in the Barnett Shale and Haynesville Shale will be substantially offset as our contractual protections of minimum volume commitment and rate redetermination work to maintain our financial performance in these regions.

We believe this trend may present investment opportunities in our liquids-rich areas of operation, such as the Mid-Continent region and may present an opportunity for us to enter the market of gathering and transporting oil and processing natural gas liquids as we believe those services fit well with our current business model.

The recent natural gas price environment has resulted in lower drilling activity generally, resulting in fewer new well connections and, in some cases, temporary curtailments of production throughout the areas in which we operate. A continued low gas price environment may result in further reductions in drilling activity or temporary curtailments of production. We have no control over this activity. In addition, further decline in commodity prices could affect production rates and the level of capital invested by Chesapeake and other producers in the exploration for and development of new natural gas reserves. Our opportunity to connect new wells to our systems is dependent on natural gas producers and shippers.

Competition

Given that substantially all of the natural gas gathered and transported through our systems is owned by Chesapeake, Total, other producers and their working interest partners within our acreage dedications, we do not currently face significant competition for our natural gas volumes. In addition, Chesapeake and Total have dedicated all of their natural gas produced from existing and future wells located on lands within our acreage dedication in the Barnett Shale region, and Chesapeake has made a similar dedication in our Haynesville and Mid-Continent regions. Chesapeake and other producers have provided long-term acreage dedications in the Marcellus Shale region.

In the future, we may face competition for Chesapeake’s production drilled outside of our acreage dedication and in attracting third-party volumes to our systems. Additionally, to the extent we make acquisitions from third parties we could face incremental competition. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies. We believe that our competitors in each region include:

• Barnett Shale—Energy Transfer Partners, Crosstex Energy, Crestwood Midstream Partners, Freedom Pipeline, Peregrine Pipeline, XTO Energy, EOG Resources, DFW Mid-Stream and Enbridge Energy Partners;

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• Haynesville Shale—TGGT Holdings, Enterprise Products Partners, Kinderhawk Field Services, CenterPoint Field Services, and Energy Transfer Partners;

• Marcellus Shale—Williams Partners, Penn Virginia Resource Partners, Caiman Energy, MarkWest Energy Partners and Talisman Energy; and

• Mid-Continent—Enogex, Atlas Pipeline Partners, Enbridge and DCP Midstream.

Employees

At every level of our operations, our employees are critical to our success and committed to operational excellence. Our senior management team has impressive experience building, acquiring and managing midstream and other assets. Their focus is on optimizing our business and expanding operations. On an operations level, our supervisory and field personnel are empowered with the training, tools and confidence required to succeed in their jobs.

The officers of our general partner manage our operations and activities. As of December 31, 2011, our general partner and Chesapeake jointly employed approximately 445 people who operate our business pursuant to an employee secondment agreement between our general partner and Chesapeake and certain of Chesapeake’s affiliates and, with respect to our Chief Executive Officer, pursuant to a shared services agreement between our general partner and Chesapeake. None of these employees are covered by collective bargaining agreements and our general partner and Chesapeake consider their employee relations to be good.

Safety and Maintenance

We are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the Department of Transportation (“DOT”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002 (“PSIA”) which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, and reauthorized through 2015 by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“PSRC”). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in “high-consequence areas.” The PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in “high-consequence areas,” such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. In addition to reauthorizing the PSIA through 2015, the PSRC expanded DOT’s authority under the PSIA and requires DOT to evaluate whether integrity management programs should be expanded beyond the high-consequence areas, authorizes DOT to promulgate regulations requiring the use of automatic and remote-controlled shut-off values for new or replaced pipelines, and requires DOT to promulgate regulations requiring the use of excess flow values where feasible. The PSRC also requires transportation-related onshore facilities to comply with recordkeeping and inspection requirements under the Clean Water Act and, beginning two years after enactment, requires pipeline to consider seismicity in their assessments of pipeline integrity.

We or the entities in which we own an interest inspect our pipelines regularly using equipment rented from third-party suppliers. Third parties also assist us in interpreting the results of the inspections.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter

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standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency (“EPA”) community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.

Regulation of Operations

Natural gas gathering and intrastate transportation facilities are exempt from the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act (“NGA”). Although FERC has not made any formal determinations with respect to any of our facilities, we believe that our natural gas pipelines and related facilities are engaged in exempt gathering and intrastate transportation and, therefore, are not subject to FERC jurisdiction.

FERC regulation affects our gathering and compression business generally. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, capacity release and market transparency and market center promotion, directly and indirectly affect our gathering business. In addition, the distinction between FERC-regulated transmission facilities and federally unregulated gathering and intrastate transportation facilities is a fact-based determination made by FERC on a case by case basis; this distinction has also been the subject of regular litigation and change. The classification and regulation of our gathering and intrastate transportation facilities are subject to change based on future determinations by FERC, the courts or Congress.

Our natural gas gathering operations are subject to ratable take and common purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination.

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Environmental Matters

General

Our operation of pipelines, plants and other facilities for the gathering, treating and compression of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations can restrict or impact our business activities in many ways, such as:

• requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of our wastes;

• limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;

• requiring investigatory and remedial actions to limit pollution conditions caused by our operations or attributable to former operations; and

• prohibiting the operations of facilities deemed to be in non-compliance with permits issued pursuant to such environmental laws and regulations.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial obligations, and the issuance of orders enjoining future operations or imposing additional compliance requirements. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.

Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Hazardous Substances and Waste

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes, and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” or “Superfund law”) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include current and prior owners or operators of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA

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also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although natural gas is not classified as a hazardous substance under CERCLA, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

We also generate solid wastes, including hazardous wastes, that are subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements relating to the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

We currently own or lease, and our predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

Air Emissions

Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. For example, the Texas Commission on Environmental Quality (“TCEQ”) has recently adopted new rules governing emissions of regulated pollutants from oil and natural gas facilities and continues to evaluate existing air regulations and proposed revisions to existing regulations as well as seek to promulgate new regulations that meet or exceed federal requirements. Such revised or new rules would establish new limits on emissions from some of our facilities as well as require implementation of best practices and/or technology and new monitoring and record keeping requirements. In addition, on July 28, 2011, the EPA published proposed New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAP”) that are expected to both amend existing NSPS and NESHAP standards for oil and gas facilities as well as create a new NSPS for oil and gas production, transmission and distribution facilities. Moreover, the federal Clean Air Act and analogous state laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements

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could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we are in substantial compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the U.S. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition, results of operations or cash flow.

Hydraulic Fracturing

Hydraulic fracturing is an important and common practice that is used by our customers to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and a small percentage of chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is regulated by state agencies, typically the state’s oil and gas commission. A number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of natural gas that our customers produce, and could thereby adversely affect our revenues and results of operations. For further discussion, see “Risk Factors— Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.”

Endangered Species

The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.

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Global Warming and Climate Change

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules. With regard to the monitoring and reporting of greenhouse gases, on November 30, 2010, the EPA published a final rule expanding its existing greenhouse gas emissions reporting rule published in October 2009 to include natural gas processing, transmission, storage and distribution activities, which may include certain of our operations, beginning in 2012 for emissions occurring in 2011. In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and some states, primarily outside of our areas of operations, have already taken legal measures to reduce emissions of greenhouse gases.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the natural gas we gather, treat and transport. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.

Title to Properties and Rights-of-Way

Our real property falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our pipelines and facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our pipelines and facilities are located are held by us pursuant to surface leases, easements, rights-of-way, permits or licenses between us and the fee owner of the lands. We, or our predecessor, have leased land rights (as provided above) to much of these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

Legal Proceedings

We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please read “—Regulation of Operations” and “—Environmental Matters.”

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ITEM 1A. Risk Factors

Risks Related to Our Business

We are dependent on Chesapeake for a substantial majority of our revenues. Therefore, we are indirectly subject to the business risks of Chesapeake. We have no control over Chesapeake’s business decisions and operations, and Chesapeake is under no obligation to adopt a business strategy that favors us.

Historically, we have provided substantially all of our natural gas gathering, treating and compression services to Chesapeake and its working interest partners. For the year ended December 31, 2011, Chesapeake accounted for approximately 84 percent of the natural gas volumes on our gathering systems and 83 percent of our revenues. We expect to derive a substantial majority of our revenues from Chesapeake for the foreseeable future. Therefore, any event, whether in our area of operations or otherwise, that adversely affects Chesapeake’s production, financial condition, leverage, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the business risks of Chesapeake, some of which are the following:

• the volatility of natural gas and oil prices, which could have a negative effect on the value of its oil and natural gas properties, its drilling programs or its ability to finance its operations;

• the availability of capital on an economic basis to fund its exploration and development activities;

• its ability to replace reserves, sustain production and begin production on certain leases that may otherwise expire;

• uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production;

• its drilling and operating risks, including potential environmental liabilities;

• transportation capacity constraints and interruptions;

• adverse effects of governmental and environmental regulation; and

• losses from pending or future litigation.

If Chesapeake, Total or other producers do not increase the volumes of natural gas they provide to our gathering systems, our growth strategy and ability to increase cash distributions to our unitholders may be adversely affected. Chesapeake has recently announced plans to reduce drilling in certain of our areas of operation.

Our ability to increase the throughput on our gathering systems will be substantially dependent on receiving increased volumes from Chesapeake, Total and other producers. Other than the scheduled increases in the minimum volume commitments provided for in our gas gathering agreements with Chesapeake and Total, our customers are not obligated to provide additional volumes to our systems, and they may determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. For example, Chesapeake previously announced its intention to increase operations in liquids-rich areas and, more recently, in response to historically low natural gas prices, Chesapeake announced that it is reducing dry gas drilling, completions, production and leasehold expenditures wherever feasible, including by operating fewer drilling rigs in the Barnett Shale, Haynesville Shale and Marcellus Shale regions. A reduction in the natural gas volumes supplied by Chesapeake, Total or other producers could result in reduced throughput on our systems and adversely impact our ability to grow our operations and increase cash distributions to our unitholders.

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We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.

We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution on each of our common units, subordinated units and the two percent general partner interest outstanding. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

• the volume of natural gas we gather, treat and compress;

• the level of production of, the demand for, and, indirectly, the price of natural gas;

• the level of our operating and general and administrative costs;

• regulatory action affecting the supply of or demand for natural gas, our operations, the rates we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and

• prevailing economic conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

• the level of capital expenditures we make, including capital expenditures for connecting new operated drilling pads or new operated wells of Chesapeake, Total or other producers in our acreage dedications as required by our gas gathering agreements;

• the cost of acquisitions, if any;

• our debt service requirements and other liabilities;

• fluctuations in our working capital needs;

• our ability to borrow funds and access capital markets;

• restrictions contained in our debt agreements;

• the amount of cash reserves established by our general partner; and

• other business risks affecting our cash levels.

The amount of cash available for distribution will also be reduced by the amount we reimburse Chesapeake for its provision of certain general and administrative services and any additional services we may request from Chesapeake, each pursuant to our services agreement with Chesapeake; the costs and expenses of employees seconded to us pursuant to the employee secondment agreement; and certain costs and expenses incurred in connection with the services of Mr. Stice as the chief executive officer of our general partner pursuant to the shared services agreement. Other than the volumetric cap on general and administrative expenses included in the services agreement, our reimbursement obligations are uncapped. In addition, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. Under our partnership agreement, our general partner determines in good faith the amount of these expenses.

Chesapeake’s level of indebtedness could adversely affect our ability to grow our business, our ability to make cash distributions to our unitholders and our credit ratings and profile.

Chesapeake must devote a portion of its cash flows from operating activities to service its indebtedness, and such cash flows are therefore not available for further development activities, which

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may reduce the volumes Chesapeake delivers to our gathering systems. Furthermore, a higher level of indebtedness at Chesapeake increases the risk that it may default on its obligations, including under its gas gathering agreements with us. Such a default could occur after the conversion of the subordinated units as a result of our general partner’s ability, for purposes of testing whether the subordination period has ended, to include as “earned” in a particular quarter its prorated estimates of shortfall payments to be earned by the end of the then current calendar year under the minimum volume commitments contained in certain of our gas gathering agreements. As of December 31, 2011, Chesapeake had long-term indebtedness of approximately $10.6 billion, with $1.7 billion of outstanding borrowings drawn under its $4.0 billion revolving credit facility and $1 million of outstanding borrowings drawn under its $600 million midstream revolving credit facility and $29 million of outstanding borrowings under its $500 million oilfield services revolving credit facility. The covenants contained in the agreements governing Chesapeake’s outstanding and future indebtedness may limit its ability to borrow additional funds for development and make certain investments, which also may reduce the volumes Chesapeake delivers to our gathering systems.

Chesapeake’s debt ratings for its senior notes are currently below investment grade. If these ratings are lowered in the future, the interest rate and fees Chesapeake pays on its revolving credit facilities will increase. Credit rating agencies such as Standard & Poor’s and Moody’s will likely consider Chesapeake’s debt ratings when reviewing ours because of Chesapeake’s ownership interest in us, the significant commercial relationships between Chesapeake and us, and our reliance on Chesapeake for a substantial majority of our revenues. If one or more credit rating agencies were to downgrade the outstanding indebtedness of Chesapeake, we could experience an increase in our borrowing costs or difficulty accessing the capital markets. Such a development could adversely affect our ability to grow our business and to make cash distributions to our unitholders.

Our general partner may guarantee or pledge any or all of its assets (other than its general partner interest, except as permitted by the partnership agreement) to secure the indebtedness of any of its affiliates. If our general partner were required to honor its guarantee or if lenders foreclosed on our general partner’s assets, the ability of our general partner to manage our business might be adversely affected. If our general partner were unable to meet any obligations to such lenders, it might be required to file for bankruptcy, which would cause our dissolution under our partnership agreement and which might have other adverse effects.

In addition to Chesapeake, we are dependent on Total and other producers for a significant amount of the natural gas that we gather, treat and compress. A material reduction in Total’s or one or more other producers’ production gathered, treated or compressed by us may result in a material decline in our revenues and cash available for distribution.

We rely on Total and other producers such as Statoil, Anadarko, Epsilon, Mitsui and Chief for a significant amount of the natural gas that we gather, treat and compress. These customers may suffer a decrease in production volumes in the areas serviced by us. We are also subject to the risk that one or more of these customers default on its obligations under its gas gathering agreements with us. Not all of our counterparties under our gas gathering agreements are rated by credit rating agencies. Accordingly, this risk may be more difficult to evaluate than it would be with rated contract counterparties. A loss of a significant portion of the natural gas volumes supplied by Total or one or more other producers, or any nonpayment or late payment by Total or one more other producers of our fees, could result in a material decline in our revenues and our cash available for distribution.

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Because of the natural decline in production from existing wells in our areas of operation, our success depends on our ability to obtain new sources of natural gas, which is dependent on factors beyond our control. Any decrease in the volumes of natural gas that we gather could adversely affect our business and operating results.

The volumes that support our business are dependent on the level of production from natural gas wells connected to our gathering systems, the production from which may be less than we expect and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain non-dedicated sources of natural gas include (i) the level of successful drilling activity near our systems and (ii) our ability to compete for volumes from successful new wells.

We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering systems or the rate at which production from a well declines. In addition, we have no control over Chesapeake, Total or other producers and their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected energy prices, demand for hydrocarbons, relative pricing of oil and natural gas, levels of reserves, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs, and other production and development costs.

Fluctuations in energy prices can also greatly affect the development of new natural gas reserves. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions; worldwide political conditions, such as the recent instability in Africa and the Middle East; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported liquefied natural gas (“LNG”); the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional pricing differentials; the price and availability of alternative fuels; the effect of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural gas, LNG and other commodities. Declines in natural gas prices could have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our gathering and treating assets. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain levels of throughput, it could reduce our revenue and impair our ability to make cash distributions to our unitholders.

In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems in unconventional resource plays, as the basins in those plays generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Accordingly, volumes on our systems serving unconventional resource plays may need to be replaced at a faster rate to maintain or grow the current volumes than may be the case in other regions of production. In addition to significant capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to estimate higher maintenance capital expenditures over time, which will reduce our cash available for distribution from operating surplus.

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If one of our gas gathering agreements were to be terminated by a customer as a result of our failure to perform certain obligations under the agreement, and we were unable to secure comparable alternative arrangements, our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders would be adversely affected.

Our gas gathering agreements are terminable if we fail to perform any of our material obligations and fail to correct such non-performance within specified periods, although under certain of our gas gathering agreements if our failure to perform relates to only one or more facilities or gathering systems, such agreement is terminable only as to such facilities or systems. Additionally, if a gas gathering agreement is terminated as to only a particular Barnett Shale gathering system, the minimum volume commitment may be reduced for gas volumes that would have been gathered on the terminated gathering system. After the termination of a gas gathering agreement, a customer might not continue to contract with us to provide gathering services, the terms of any renegotiated agreements may not be as favorable as our existing agreements, and we may not be able to enter into comparable alternative arrangements with third parties. To the extent a customer terminates a gas gathering agreement or there is a reduction in our minimum volume commitments, our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders may be adversely affected.

Certain of the provisions contained in our gas gathering agreements may not operate as intended, including the volumetric-based cap associated with fuel and lost and unaccounted for gas, which could subject us to direct commodity price risk and adversely affect our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders.

Our gas gathering agreements contain provisions relating to, among other items, periodic fee redeterminations, changes in laws affecting our operations and fuel and lost and unaccounted for gas. These and other provisions of our gas gathering agreements might not operate as intended.

The fee redetermination and other provisions of our gas gathering agreements are intended to support the stability of our cash flows and were designed with the goal of supporting a return on our invested capital, which is not equivalent to ensuring that our business will generate a particular amount of cash flow. Our fee redetermination provisions do not take into consideration all expenses and other variables, including certain operating expenditures, that would affect our return on invested capital. In addition, our gathering rates may be adjusted upward or downward following a fee redetermination, subject to specified caps in certain cases. The change in law provisions contained in our gas gathering agreements are designed to provide for our reimbursement by customers of certain taxes, fees, assessments and other charges that we may incur as a result of changes in law. These change in law provisions may not cover all legal or regulatory changes that could have an adverse economic impact on our operations. We have also agreed with our customers on caps on fuel and lost and unaccounted for gas on certain of our systems. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel and lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

If these or other provisions of our gas gathering agreements do not operate as intended, our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders could be adversely affected.

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We do not obtain independent evaluations of natural gas reserves connected to our gathering systems; therefore, in the future, volumes of natural gas on our systems could be less than we currently anticipate.

We do not obtain independent evaluations of natural gas reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. Notwithstanding the contractual protections in certain of our gas gathering agreements, including minimum volume commitments in our Barnett Shale region (with respect to Chesapeake and Total), and Haynesville Shale region (with respect to Chesapeake), and fee redetermination provisions, if the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

We are generally required to make capital expenditures under our gas gathering agreements. If we are unable to obtain needed capital or financing on satisfactory terms to fund required capital expenditures or capital expenditures to otherwise expand our asset base, our ability to grow cash distributions may be diminished or our financial leverage could increase.

Under our gas gathering agreements, upon the request of any of our customers, we are generally required to connect new operated drilling pads and new operated wells in our Barnett Shale and Haynesville Shale regions during the respective minimum volume commitment periods, and with respect to our Mid-Continent region prior to June 30, 2019, to use commercially reasonable efforts to do the same. In the Marcellus Shale region, we generally have the option to connect new operated drilling pads and new operated wells, but we may be required to connect by the customer under certain circumstances. In addition, in order to increase our overall asset base, we will need to make significant expansion capital expenditures in the future. If we do not make sufficient or effective expansion capital expenditures, including such new drilling pad and new well connections, we will be unable to expand our business operations and will be unable to raise the level of our future cash distributions. If we are delayed in making a connection to an operated drilling pad or well, Chesapeake or Total in the Barnett Shale acreage dedication or Chesapeake in the Haynesville Shale acreage dedication, as its sole remedy for such delayed connection, would be entitled to a delay in the minimum volume obligation for gas volumes that would have been produced from the delayed connections. Any delay in the minimum volume obligations for drilling pad or well connections could reduce our revenues under the gas gathering agreements and our cash available for distribution.

To the extent that our cash from operations is insufficient to fund our expansion capital expenditures, we may be required to incur borrowings or raise capital through public or private debt or equity offerings. Our ability to obtain bank financing or to access the capital markets may be limited by our financial condition at the time of any such financing or offering and by the covenants in our existing debt agreements, as well as by general economic and capital market conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional common units may result in significant unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

We are required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available for distribution to unitholders than if actual maintenance capital expenditures were deducted.

Our partnership agreement requires us to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus. The amount of estimated maintenance capital

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expenditures deducted from operating surplus will be subject to review and change by our conflicts committee at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing and make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the anticipated level and could be required to reduce our distributions.

We conduct certain operations through joint ventures that may limit our operational flexibility.

Our operations in the Marcellus Shale region are conducted through joint venture arrangements, and we may enter additional joint ventures in the future. In a joint venture arrangement, we have less operational flexibility, as actions must be taken in accordance with the applicable governing provisions of the joint venture. In certain cases:

• we have limited ability to influence or control certain day to day activities affecting the operations;

• we cannot control the amount of capital expenditures that we are required to fund with respect to these operations;

• we are dependent on third parties to fund their required share of capital expenditures;

• we may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets; and

• we may be forced to offer rights of participation to other joint venture participants in the area of mutual interest.

In addition, our joint venture participants may have obligations that are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture and to pay their share of capital and other costs of the joint venture. The performance and ability of the third parties to satisfy their obligations under joint venture arrangements is outside our control. If these parties do not satisfy their obligations under these arrangements, our business may be adversely affected. Our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives, and disputes between us and our joint venture partners may result in delays, litigation or operational impasses. The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to conduct our Marcellus Shale operations or any other business that is the subject of a joint venture, which could in turn negatively affect our financial condition and results of operations.

Our industry is highly competitive, and increased competitive pressure could adversely affect our ability to execute our growth strategy.

We compete with similar enterprises in our areas of operation other than with respect to natural gas production dedicated to us pursuant to our gas gathering agreements with Chesapeake, Total and other producers. Our competitors may expand or construct gathering systems and associated infrastructure that would create additional competition for the services we provide to our customers. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flow could be adversely affected by the activities of our competitors and our

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customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Part of our growth strategy is to attract volumes to our systems from unaffiliated third parties over time. However, we have historically provided gathering and related services to unaffiliated third parties on only a limited basis, and we may not be able to attract any material third-party volumes to our systems. Our efforts to attract new unaffiliated customers may be adversely affected by our need to prioritize allocating capital expenditures towards connecting new operated drilling pads and new operated wells for Chesapeake, Total and other producers as well as our desire to provide our services pursuant to fixed-fee contracts. Our potential customers may prefer to obtain services under other forms of contractual arrangements pursuant to which we would be required to assume some direct commodity price exposure. In addition, we will need to establish a reputation with our potential customer base for providing high quality service in order to successfully attract material volumes from unaffiliated third parties.

If third-party pipelines or other facilities interconnected to our gathering systems become partially or fully unavailable, or if the volumes we gather do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

Our natural gas gathering systems connect to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third-party pipelines or facilities is not within our control. These pipelines and other facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, curtailments of receipt or deliveries due to insufficient capacity or for any other reason. If any of these pipelines or facilities become unable to transport natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand one or more of our gathering systems, the construction may occur over an extended period of time, yet we will not receive any material increases in revenues until the project is completed. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering assets may require us to obtain new rights-of-way. We may be unable to obtain such rights-of-way and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

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If we are unable to make acquisitions on economically acceptable terms from Chesapeake or third parties, our future growth would be limited, and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis. We may fail to successfully integrate the Appalachia Midstream business with our existing business in a timely manner, which could have a material adverse effect on our business, financial condition, results of operations or cash flows, or fail to realize all of the expected benefits of the acquisition, which could negatively impact our future results of operations.

Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants, including Chesapeake. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase cash distributions to our unitholders. If we are unable to make such accretive acquisitions from Chesapeake or third parties, either because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we complete acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis. If we consummate any future acquisitions, our capitalization and results of operations may change significantly.

Any acquisition involves potential risks, including, among other things:

• mistaken assumptions about volumes, revenues and costs, including synergies;

• an inability to secure adequate customer commitments to use the acquired systems or facilities;

• an inability to successfully integrate the assets or businesses we acquire;

• the assumption of unknown liabilities;

• limitations on rights to indemnity from the seller;

• mistaken assumptions about the overall costs of equity or debt;

• the diversion of management’s and employees’ attention from other business concerns;

• operating a larger combined organization and adding operations;

• difficulties in the assimilation of the acquired assets and operations into the existing business;

• managing relationships with new customers and suppliers for whom we have not previously provided products or services;

• maintaining an effective system of internal controls related to the acquired business and integrating internal controls, compliance under the Sarbanes-Oxley Act of 2002 and other regulatory compliance and corporate governance matters;

• an increase in our indebtedness;

• potential environmental or regulatory compliance matters or liabilities and title issues, including certain liabilities arising from the operation of the acquired business before the acquisition;

• unforeseen difficulties operating in new geographic areas; and

• customer or key employee losses at the acquired businesses.

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Integration of the Appalachia Midstream business with our existing business will be a complex, time-consuming and costly process, particularly given that the acquisition will significantly increase our size, and diversify the geographic areas in which we operate and our customer base. A failure to successfully integrate the Appalachia Midstream business with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations or cash flows. In addition, the Appalachia Midstream business may actually perform at levels below the forecasts we used to evaluate the Appalachia Midstream business, due to factors that are beyond our control. If the Appalachia Midstream business performs at levels below the forecasts we used to evaluate the acquisition, then our future results of operations and our financial condition could be negatively impacted. Although CMD has agreed to pay us the difference between quarterly EBITDA received from the Appalachia Midstream business and specified targeted EBITDA, CMD is not required to make such payments beyond 2013, which could result in a decline in our reported results of operations from the business after such time. In addition, if we fail to operate the Appalachia Midstream business assets to the satisfaction of our customers and the other owners of the assets, we may suffer reputational harm, which could make our planned expansions and acquisitions of new customers more difficult.

Our right of first offer with respect to certain of Chesapeake’s future midstream divestitures as well as development and acquisition opportunities adjacent to certain of our existing areas of operation is subject to risks and uncertainty, and thus may not enhance our ability to grow our business.

Subject to certain exceptions, our omnibus agreement provides us with a right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation in the Barnett Shale and Mid-Continent region. The consummation and timing of any future transactions pursuant to the exercise of our right of first offer with respect to any particular business opportunity will depend upon, among other things, our ability to negotiate definitive agreements with respect to such opportunities and our ability to obtain financing on acceptable terms. We may not be able to successfully consummate future transactions pursuant to these rights. Additionally, Chesapeake is under no obligation to accept any offer made by us with respect to such opportunities. Furthermore, for a variety of reasons, we may decide not to exercise these rights when they become available, and our decision will not be subject to unitholder approval. In addition, first offer rights under the omnibus agreement may be terminated by Chesapeake at any time each of GIP and Chesapeake holds less than half of the ownership interest it currently holds in Chesapeake Midstream Ventures.

Our exposure to direct commodity price risk may increase in the future.

We currently generate substantially all of our revenues pursuant to fixed-fee contracts under which we are paid based on the volumes of natural gas that we gather and treat rather than the value of the underlying natural gas. Consequently, our existing operations and cash flows have limited exposure to direct commodity price risk. Although we intend to enter into similar fixed-fee contracts with new customers in the future, our efforts to obtain such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in the future that have a greater exposure to fluctuations in commodity prices than our current operations. Future exposure to the volatility of oil and natural gas prices could have a material adverse effect on our business, results of operations and financial condition.

We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain

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necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured, our operations and financial results could be adversely affected.

Our operations are subject to all of the risks and hazards inherent in the midstream energy business, including:

• damage to pipelines and facilities, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, explosions and other natural disasters and acts of terrorism;

• inadvertent damage from construction, farm and utility equipment;

• leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities; and

• other hazards.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. In addition, our Barnett Shale area in the Dallas-Fort Worth, Texas metropolitan area poses unique challenges and risks associated with drilling for natural gas and the installation and operation of midstream infrastructure in urban and suburban communities. We are not fully insured against all risks inherent in our business. For example, we do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. Additionally, we do not have any business interruption/loss of income insurance that would provide coverage in the event of damage to any of our facilities. Although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not adequately insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets for potential environmental liabilities pursuant to our indemnification rights.

We lease substantially all of our compression capacity from a single provider under long-term fixed price agreements, which could result in disruptions to our operations or our paying above-market prices for our compression requirements in the future.

Compression of our customers’ natural gas is a key component of the services we provide and our largest operating expense. Given that wells produce at progressively lower field pressures as the underlying resources are depleted, field compression is required to maintain sufficient pressure across our gathering systems. We lease substantially all of the compression capacity for our existing gathering systems in the Marcellus Shale from MidCon Compression, L.L.C. (“MidCon Compression”), a wholly owned subsidiary of Chesapeake, under a long-term contract expiring on January 31, 2021 pursuant to

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which we have agreed to pay specified monthly rates under a fixed-fee structure subject to an annual escalator. This agreement is not subject to an exclusivity provision. We lease substantially all of the compression capacity for our existing gathering systems outside the Marcellus Shale from MidCon Compression under a long-term contract expiring on September 30, 2019 pursuant to which we have agreed to pay specified monthly rates under a fixed-fee structure subject to an annual escalator and a redetermination of such specified monthly rates to market rates effective no later than October 1, 2016. Under this agreement, we have granted MidCon Compression the exclusive right to lease and rent compression equipment to us in our Barnett Shale, Haynesville Shale and Mid-Continent acreage dedications through September 30, 2016. Thereafter, we have the right to continue leasing such equipment through September 30, 2019 at market rental rates to be agreed upon by the parties or to lease compression equipment from unaffiliated third parties. If market rates for compression are less than the specified monthly rates prior to redetermination under the agreement, then the rates we pay for compression under this contract may be higher than the rates we could obtain from a third party. In addition, if MidCon Compression were to default on its obligations under the terms of our agreements, we may not be able to replace such compression capacity in a timely manner or otherwise on terms consistent with our agreements with MidCon Compression or at all. This could result in our failure to meet our contractual obligations to our customers, which could expose us to damages, reduce revenues and have a material adverse effect on our financial condition, results of operation and cash flows.

Restrictions in our revolving credit facility and indentures could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our units.

We are dependent upon the earnings and cash flow generated by our operations in order to meet our debt service obligations and to make cash distributions to our unitholders. The operating and financial restrictions and covenants in our revolving credit facility, our indentures and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders. For example, our revolving credit facility and indentures restrict our ability to, among other things:

• incur additional debt or issue guarantees;

• incur or permit certain liens to exist;

• make certain investments, acquisitions or other restricted payments;

• dispose of assets;

• engage in certain types of transactions with affiliates;

• merge, consolidate or transfer all or substantially all of our assets; and

• prepay certain indebtedness.

Furthermore, our revolving credit facility contains covenants requiring us to maintain a consolidated leverage ratio of not more than 5.00 to 1 (or 5.50 to 1 during an approximate two-quarter period following the completion of certain acquisitions) and an interest coverage ratio of not less than 2.5 to 1.

The provisions of our revolving credit facility and indentures may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility or indentures could result in an event of default which could enable our lenders or noteholders, subject to the terms and conditions of the revolving credit facility and indentures, to

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declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, the lenders under our revolving credit facility could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment. The revolving credit facility also has cross default provisions that apply to any other indebtedness we may have with an outstanding principal amount in excess of $15 million and the indentures have cross default provisions that apply to other indebtedness with an outstanding principal amount of $50 million.

Our current indebtedness and debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our current leverage and future level of indebtedness could have important consequences to us, including the following:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including required drilling pad connections and well connections pursuant to certain of our gas gathering agreements as well as acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;

• our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;

• we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

• our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to affect any of these actions on satisfactory terms or at all.

The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price will be impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in

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interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make cash distributions at our intended levels.

Due to our lack of industry diversification, adverse developments in our segment of the midstream industry could adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.

Our operations are focused on natural gas gathering, treating and compression services. Due to our lack of industry diversification, adverse developments in our current segment of the midstream industry could have a significantly greater impact on our financial condition, results of operations and cash flows than if our operations were more diversified.

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.

An increasing percentage of our customers’ oil and gas production is being developed from unconventional sources, such as deep gas shales. These reservoirs require hydraulic fracturing completion processes to release the gas from the rock so it can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. A number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with shale development, including hydraulic fracturing. In addition, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the process of drafting guidance documents related to this assertion of regulatory authority. In addition, some states and municipalities have adopted, and other states and municipalities are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress to provide for such regulation. We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through our gathering systems which would materially adversely affect our revenues and results of operations.

We may incur significant costs and liabilities in complying with, or as a result of a failure to comply with, new or existing environmental laws and regulations, and changes in environmental laws or regulations could adversely impact our customers’ production and operations, which could have a material adverse effect on our results of operations and cash flows.

Our natural gas gathering, treating and compression operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations, including obtaining permits to conduct regulated activities, incurring capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and imposing substantial liabilities and remedial obligations relating to pollution or emissions that may result from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring

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regulated parties to undertake difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenues.

Moreover, changes in environmental laws and regulations occur frequently, and stricter laws, regulations or enforcement policies could significantly increase our compliance costs. Further, stricter requirements could negatively impact our customers’ production and operations. For example, on January 26, 2011, the TCEQ adopted new rules governing emissions of regulated pollutants from oil and natural gas facilities. TCEQ continues to evaluate existing air regulations and proposed revisions to existing regulations as well as seek to promulgate new regulations that meet or exceed federal requirements. Such revised or new rules would establish new limits on emissions from some of our facilities as well as require implementation of best practices and/or technology and new monitoring and record keeping requirements. Similar regulatory changes could lead to more stringent air permitting, increased regulation and possible enforcement actions against the regulated community. Additionally, on July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas processing operations. Specifically, the EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas processing activities. The EPA is expected to receive public comment and hold hearings regarding the proposed rules and must take final action on them by April 3, 2012. If finalized, these rules could require a number of modifications to our customers’ as well as our operations, including the installation of new equipment. If these or other initiatives result in an increase in regulation, it could increase our costs or reduce our customers’ production, which could have a material adverse effect on our results of operations and cash flows.

There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry practices, our handling of hydrocarbon wastes and air emissions and discharges related to our operations. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may not be able to recover all or any of these costs from insurance.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas services we provide.

In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air

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Act. The EPA adopted two sets of rules, effective January 2, 2011, regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. With regard to the monitoring and reporting of greenhouse gases, on November 30, 2010, the EPA published a final rule expanding its existing greenhouse gas emissions reporting rule published in October 2009 to include onshore oil and natural gas processing, transmission, storage, and distribution activities, which may include certain of our operations, beginning in 2012 for emissions occurring in 2011. In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and some states, primarily outside of our areas of operations, have already taken legal measures to reduce emissions of greenhouse gases.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the natural gas we gather, treat and transport. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.

If our assets became subject to regulation by FERC or regulations of state and local agencies were to change, our financial condition, results of operations and cash flows could be materially and adversely affected.

Natural gas gathering and intrastate transportation facilities are exempt from the jurisdiction of FERC under the NGA. Although FERC has not made any formal determinations respecting any of our facilities, we believe that our natural gas pipelines and related facilities are engaged in exempt gathering and intrastate transportation and, therefore, are not subject to FERC jurisdiction. If FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of services provided by such facility would be subject to regulation by FERC. Such regulation could decrease revenues, increase operating costs, and depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or the Natural Gas Policy Act, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by FERC.

Moreover, FERC regulation affects our gathering and compression business generally. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, capacity release and market transparency and market center promotion, directly and indirectly affect our gathering business. In addition, the distinction between FERC-regulated transmission facilities and federally unregulated gathering and intrastate transportation facilities is a fact-based determination made by FERC on a case by case basis; this distinction has also been the subject of regular litigation and change. The classification and regulation of our gathering and intrastate transportation facilities are subject to change based on future determinations by FERC, the courts or Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of

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interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. We cannot predict what new or different regulations federal and state regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Such regulations may have a material adverse effect on our financial condition, results of operations and cash flows.

If our services agreement with Chesapeake is terminated, or if Chesapeake fails to provide us with adequate services, we will have to obtain those services internally or through third-party arrangements.

We depend on Chesapeake to provide us certain general and administrative services and any additional services we may request pursuant to our services agreement. The term of the provision of general and administrative services by Chesapeake under the services agreement will continue until December 31, 2012 and will extend for additional twelve-month periods unless we or Chesapeake provides 180 days’ prior written notice of termination, subject to certain conditions and limitations. Though Chesapeake will agree to perform such services using no less than a reasonable level of care in accordance with industry standards, if Chesapeake fails to provide us adequate services, or if the services agreement is terminated for any reason, we will have to obtain these services internally or through third-party arrangements which may result in increased costs to us.

If we fail to maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

Prior to our IPO in July 2010, we were not required to file reports with the SEC. Upon the completion of the offering, we became subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We prepare our consolidated financial statements in accordance with generally accepted accounting principles (“GAAP”), but prior to December 31, 2011, our internal accounting controls were not required to meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. We were required to comply with Section 404 for our fiscal year ended December 31, 2011. Any failure to maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our or our independent registered public accounting firm’s conclusions about the effectiveness of our internal controls. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

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Risks Inherent in an Investment in Us

Chesapeake and GIP, through their joint ownership of Chesapeake Midstream Ventures, indirectly own and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Chesapeake, GIP and Chesapeake Midstream Ventures, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our common unitholders.

Chesapeake Midstream Ventures, which is owned and controlled by Chesapeake and GIP, owns and controls our general partner and appoints all of the officers and directors of our general partner, some of whom are also officers and directors of Chesapeake, GIP and/or Chesapeake Midstream Ventures. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, Chesapeake Midstream Ventures. Conflicts of interest will arise between Chesapeake, GIP, Chesapeake Midstream Ventures and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Chesapeake, GIP and/or Chesapeake Midstream Ventures over our interests and the interests of our common unitholders. These conflicts include the following situations, among others:

• Neither our partnership agreement nor any other agreement requires Chesapeake, GIP or Chesapeake Midstream Ventures to pursue a business strategy that favors us.

• Our general partner is allowed to take into account the interests of parties other than us, such as Chesapeake, GIP or Chesapeake Midstream Ventures, in resolving conflicts of interest.

• The chief executive officer of our general partner will also devote significant time to the business of Chesapeake and will be compensated by Chesapeake accordingly.

• Our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

• Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

• Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

• Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.

• Our general partner determines which costs incurred by it are reimbursable by us.

• Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

• Our partnership agreement permits us to classify up to $120 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that

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would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.

• Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

• Our general partner intends to limit its liability regarding our contractual and other obligations.

• Disputes may arise under our gas gathering agreement with Chesapeake, including with respect to fee redeterminations or the determination of amounts payable as liquidated damages upon Chesapeake’s failure, if any, to meet its minimum volume commitments under the agreement.

• Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80 percent of the common units.

• Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

• Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

• Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our

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revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.

Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

• how to allocate business opportunities among us and its affiliates;

• whether to exercise its limited call right;

• how to exercise its voting rights with respect to the units it owns;

• whether to elect to reset target distribution levels; and

• whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above.

Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

• provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

• provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in the best interest of our partnership;

• provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

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• provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:

(a) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;

(b) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

(c) on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

(d) fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0 percent) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will equal the number of common units which would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner’s general partner interest in us (currently two percent) will be maintained at the percentage that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash

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distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner consists of seven members, two of whom have been designated by Chesapeake, two of whom have been designated by GIP and three of whom are independent. Chesapeake Midstream Ventures is the sole member of our general partner and has the right to appoint our general partner’s entire board of directors, including our three independent directors. If the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Even if holders of our common units are dissatisfied, they cannot remove our general partner currently without Chesapeake and GIP’s consent.

Our unitholders are currently unable to remove our general partner because our general partner and its affiliates own sufficient units to prevent its removal. The vote of the holders of at least 66 2/3 percent of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. As of February 22, 2012, Chesapeake and GIP own an aggregate of 69.5 percent of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and no units held by the holders of the subordinated units or their affiliates are voted in favor of that removal, all subordinated units held by our general partner and its affiliates will automatically be converted into common units. If no units held by any holder of subordinated units or its affiliates are voted in favor of that removal, all subordinated units will convert automatically into common units and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.

Our partnership agreement restricts the voting rights of unitholders owning 20 percent or more of our common units.

Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner, its affiliates, their direct transferees and their indirect transferees approved by our general partner (which approval may be granted in its sole discretion) and persons who acquired such units with the prior approval of our general partner, cannot vote on any matter.

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Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Chesapeake Midstream Ventures to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

Our general partner is jointly owned and controlled indirectly by Chesapeake and GIP. As a result, there is a possibility of deadlocks occurring with respect to important governance or other business decisions affecting us to be made by our general partner, which could adversely affect our business.

Our general partner has sole responsibility for conducting our business and for managing our operations and is controlled by its sole member, Chesapeake Midstream Ventures. As of February 22, 2012, Chesapeake and GIP each directly own a 50 percent membership interest in, and jointly control, Chesapeake Midstream Ventures. Chesapeake Midstream Ventures has the right to appoint our general partner’s entire board of directors, including our three independent directors. We expect that conflicts will arise in the future between Chesapeake, on the one hand, and GIP, on the other hand, with regard to our governance, business and operations. Important governance or other business decisions could be delayed as a result of a deadlock between Chesapeake and GIP, which could adversely affect our business.

We may issue additional units without your approval, which would dilute your existing ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

• our existing unitholders’ proportionate ownership interest in us will decrease;

• the amount of cash available for distribution on each unit may decrease;

• because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

• the ratio of taxable income to distributions may increase;

• the relative voting strength of each previously outstanding unit may be diminished; and

• the market price of the common units may decline.

Chesapeake and GIP may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

As of February 22, 2012, Chesapeake holds 33,704,666 common units and GIP holds no common units. Chesapeake and GIP hold an aggregate 69,076,122 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. Additionally, we have agreed to provide each of Chesapeake and GIP with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

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Our general partner has a call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80 percent of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return or a negative return on your investment. You may also incur a tax liability upon a sale of your units. As of February 22, 2012, Chesapeake and GIP own an aggregate of approximately 42.7 percent (exclusive of subordinated units) of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), Chesapeake and GIP will own an aggregate of approximately 69.5 percent of our outstanding common units.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

• we were conducting business in a state but had not complied with that particular state’s partnership statute; or

• your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (“Delaware Act”) we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

We incur increased costs as a result of being a publicly traded partnership.

We had no history operating as a publicly traded partnership prior to our IPO. As a publicly traded partnership, we incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required

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changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, our cash available for distribution to you would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (“IRS”) on this or any other tax matter affecting us. Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35 percent, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to you.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax each year at a maximum effective rate of 0.7 percent of our gross income apportioned to Texas in the prior year. Imposition of any such taxes may substantially reduce the cash available for distribution to you and, therefore, negatively impact the value of an investment in our common units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation

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at any time. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that would have affected certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the legislation considered would not have appeared to affect our tax treatment as a partnership, we are unable to predict whether any similar changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Because our unitholders are treated as partners in us for federal income tax purposes, we will allocate a share of our taxable income to you which could be different in amount than the cash we distribute, and you may be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you do not receive any cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest

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applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could result in audit adjustments to your tax returns without the benefit of additional deductions. Consequently, a successful IRS challenge could have a negative impact on the value of our common units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the last day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the last day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the

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capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50 percent or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50 percent threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one calendar year. Our termination could also result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

As a result of investing in our common units, you may become subject to state, local and non-U.S. taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

In addition to federal income taxes, you will likely be subject to other taxes, including non-U.S., state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file non-U.S., state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We own assets and conduct business in Arkansas, Kansas, Louisiana, Oklahoma, Pennsylvania, Texas and West Virginia. Each of these states, other than Texas, currently imposes a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, non-U.S., state and local tax returns.

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ITEM 1B. Unresolved Staff Comments

None.

ITEM 2. Properties

Substantially all of our pipelines, which are located in Texas, Louisiana, Oklahoma, Kansas, Arkansas, West Virginia, and Pennsylvania, are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights of way have been obtained may be subject to prior liens that have not been subordinated to the right of way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways. In some cases, properties on which our pipelines were built were purchased.

We believe we have satisfactory title to all of our assets. Record title to some of our assets may continue to be held by prior owners until we have made the appropriate filings in the jurisdictions in which such assets are located. Obligations under our credit facility are secured by substantially all of our assets and are guaranteed by the Partnership. Title to our assets may also be subject to other encumbrances. We believe that none of such encumbrances should materially detract from the value of our properties or our interest in those properties or should materially interfere with our use of them in the operation of our business.

Our executive offices are located in an office building located at 900 N.W. 63rd Street, Oklahoma City, Oklahoma, under a lease with Chesapeake that expires December 31, 2012, with annual renewal options. We also maintain a regional headquarters located on leased premises in Fort Worth, Texas, under a lease with Chesapeake that expires October 1, 2012, with renewal options through October 1, 2021. We also maintain regional offices located on leased premises in Texas and Oklahoma. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future and that additional office space will be available on commercially reasonable terms as needed.

For additional information regarding our properties, please read “Item 1 – Business.”

ITEM 3. Legal Proceedings

We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business.

ITEM 4. Mine Safety Disclosures

Not applicable.

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Part II

ITEM 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common units are listed on the NYSE under the symbol “CHKM.” Our common units began trading on July 29, 2010 at an initial offering price of $21.00 per unit. Prior to July 29, 2010, our equity securities were not listed on any exchange or traded in any public market. The following table sets forth the high and low sales prices of the common units as well as the amount of cash distributions declared and paid during each quarter since our IPO.

	Common Units
	High		Low		Distribution per common and subordinated unit
Year ended December 31, 2011
Fourth Quarter	$	29.21	$	24.49	$	0.3900
Third Quarter		28.90		23.93		0.3750
Second Quarter		29.06		25.52		0.3625
First Quarter		29.31		24.93		0.3500
Year ended December 31, 2010
Fourth Quarter	$	29.15	$	25.20	$	0.3375
Third Quarter		26.00		21.25		0.2165
Second Quarter		n/a		n/a		n/a
First Quarter		n/a		n/a		n/a

As of February 17, 2012, there were approximately 18 unitholders of record of the Partnership’s common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. We have also issued 69,076,122 subordinated units and ownership interests in the general partner, for which there is no established public trading market. All of the subordinated units and general partner interests are held by affiliates of our general partner. Our general partner and its affiliates receive quarterly distributions on the subordinated units only after sufficient funds have been paid to the common units.

Selected Information from our Partnership Agreement

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions, minimum quarterly distributions and IDRs.

Available cash

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending September 30, 2010, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, including reserves to fund future capital expenditures, to comply with applicable laws, or our debt instruments and other agreements, or to provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement.

Minimum Quarterly Distribution

The partnership agreement provides that, during the Subordination Period, the common units are entitled to distributions of available cash each quarter in an amount equal to the minimum quarterly

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distribution, which is $0.3375 per common unit for each full fiscal quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Furthermore, arrearages do not apply to and therefore will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the Subordination Period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to the minimum quarterly distribution.

The Subordination Period will lapse at such time when the Partnership has earned and paid at least the minimum quarterly distribution per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2013. Also, if the Partnership has earned and paid at least 150 percent of the minimum quarterly distribution on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the Subordination Period will terminate automatically. The Subordination Period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of removal. When the Subordination Period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages. All subordinated units are held indirectly by Chesapeake and GIP.

General Partner Interest and Incentive Distribution Rights

Our general partner is entitled to two percent of all quarterly distributions that we make after inception and prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its two percent general partner interest. Our general partner’s initial two percent interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us to maintain its two percent general partner interest.

Other Securities Matters

Securities Authorized for Issuance Under Equity Compensation Plans.

In connection with the closing of our IPO, our general partner adopted the Chesapeake Midstream Long-Term Incentive Plan, or “LTIP,” which permits the issuance of up to 3,500,000 units, subject to adjustment for certain events. Phantom unit grants have been made to each of the independent directors of our general partner under the LTIP. Please read the information under Item 12 of this annual report, which is incorporated by reference into this Item 5.

Unregistered Securities

On December 29, 2011, we issued 9,791,605 common units to Chesapeake Midstream Holdings, L.L.C., a wholly owned subsidiary of Chesapeake, in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(2) thereof. The common units represented a portion of the purchase price paid to Chesapeake in connection with our acquisition of Appalachia Midstream Services, L.L.C. On February 7, 2012, in connection with the Partnership’s fourth quarter 2011 distribution, the general partner made an additional capital contribution to the Partnership of approximately $5.7 million in order to maintain its two percent general partner interest in the Partnership. The contribution was effective as of December 31, 2011. This issuance was exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. During the fiscal year ended December 31, 2011, we did not sell or issue any other equity securities without the registration of these securities under the Securities Act of 1933, as amended, in reliance on exemptions from such registration requirements, which have not been previously disclosed in a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.

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ITEM 6. Selected Financial Data

The following table shows our selected financial and operating data for the periods and as of the dates indicated, which is derived from our consolidated financial statements. On August 3, 2010, we closed our IPO of 24,437,500 common units, including 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option. Upon completion of the IPO, Chesapeake and GIP contributed to us Chesapeake MLP Operating, L.L.C., which owned all of our assets since September 2009. On December 21, 2010, we closed the Springridge acquisition and on December 29, 2011 we closed the Marcellus acquisition.

The table should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements, including the notes, appearing in Items 7 and 8 of this Annual Report.

										Predecessor
	Year Ended December 31, 2011			Year Ended December 31, 2010			Three Months Ended December 31, 2009			Nine Months Ended September 30, 2009			Year Ended December 31, 2008			Year Ended December 31, 2007
							($ in thousands)
Statement of Operations Data:
Revenues(1)	$	565,929		$	459,153		$	107,377		$	358,921		$	332,783		$	191,931
Operating expenses		176,851			133,293			31,874			146,604			141,803			77,589
Depreciation and amortization expense		136,169			88,601			20,699			65,477			47,558			24,505
General and administrative expense		40,380			31,992			2,854			22,782			13,362			6,880
Impairment of property, plant and equipment and other assets(2)		—			—			—			90,207			30,000			—
(Gain) loss on sale of assets(3)		739			285			34			44,566			(5,541	)		—
Total operating expenses		354,139			254,171			55,461			369,636			227,182			108,974
Operating income (loss)		211,790			204,982			51,916			(10,715	)		105,601			82,957
Income from unconsolidated affiliates		433			—			—			—			—			—
Interest expense		(14,884	)		(7,426	)		(619	)		(347	)		(1,871	)		—
Other income		287			102			34			29			278			—
Income (loss) before income taxes		197,626			197,658			51,331			(11,033	)		104,008			82,957
Income tax expense (benefit)(4)		3,289			2,431			639			6,341			(61,287	)		31,109
Net income (loss)	$	194,337		$	195,227		$	50,692		$	(17,374	)	$	165,295		$	51,848
Net income per common unit – basic and diluted(5)	$	1.37			0.78			n/a			n/a			n/a			n/a
Net income per subordinated unit – basic and diluted(5)		1.37			0.78			n/a			n/a			n/a			n/a
Distribution per unit		1.48			0.55			n/a			n/a			n/a			n/a
Balance Sheet Data (at period end):
Net property, plant and equipment	$	2,527,924		$	2,226,909		$	1,776,415		$	2,870,547		$	2,339,473		$	965,801
Total assets		3,683,238			2,545,916			1,958,675			3,232,840			2,583,765			1,010,112
Total debt		1,062,900			249,100			44,100			12,173			460,000			—
Total equity		2,473,145			2,194,568			1,793,627			2,996,403			1,793,269			847,421
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	399,016		$	317,091		$	14,730		$	100,748		$	236,774		$	93,948
Investing activities		(1,017,104	)		(711,480	)		(46,352	)		(690,994	)		(1,384,834	)		(563,564	)
Financing activities stock		600,294			412,202			31,590			664,268			1,230,059			469,622
Key Performance Metrics:
Adjusted EBITDA(6)	$	349,473		$	293,970		$	72,683		$	189,564		$	177,896		$	107,462
Distributable cash flow(6)		261,960			218,989			n/a			n/a			n/a			n/a
Capital expenditures		418,834			216,303			46,377			756,883			1,402,449			563,564
Operational Data:
Throughput, Bcf/d(7)		2.176			1.595			1.550			2.108			1.585			1.018

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⁽¹⁾  If Chesapeake or Total does not meet its minimum volume commitment to the Partnership in the Barnett Shale region or Chesapeake does not meet its minimum volume commitment in the Haynesville Shale region under the applicable gas gathering agreement for specified annual periods, Chesapeake or Total is obligated to pay the Partnership a fee equal to the applicable fee for each one thousand cubic feet (“Mcf”) by which the applicable party’s minimum volume commitment for the year exceeds the actual volumes gathered on the Partnership’s systems. The Partnership recognizes any associated revenue in the fourth quarter. Our revenues for the three months ended December 31, 2009, include the impact of $7.7 million attributable to Chesapeake associated with the minimum volume commitment in our Barnett Shale region for 2009. For the years ended December 31, 2011 and 2010, we recognized revenue related to volume shortfall of $17.4 million and $56.8 million, respectively, because throughput in our Barnett Shale region was below contractual minimum volume commitment levels.

⁽²⁾  Our predecessor recorded an $86.2 million impairment associated with certain Mid-Continent gathering systems that are not expected to have future cash flows in excess of the book value of the systems. These systems were subsequently contributed to us as of September 30, 2009. Additionally, $4 million of debt issuance costs were expensed as a result of the amendment of our predecessor’s $460 million credit facility. During the year ended December 31, 2008, our predecessor recorded a $30.0 million impairment associated with a certain treating facility as a result of the facility’s location in an area of continued declining throughput and a reduction in the future expected throughput volumes by Chesapeake, based on its revised future development plans on the associated oil and gas properties that serve as the primary source of throughput volumes for the facility.

⁽³⁾  Our predecessor recorded a $44.6 million loss on the disposal of certain non-core and non-strategic gathering systems for the nine months ended September 30, 2009.

⁽⁴⁾  Prior to February 2008, our predecessor filed a consolidated federal income tax return and state returns as required with Chesapeake. In February 2008, upon and subsequent to contribution of assets to our predecessor by Chesapeake, our predecessor and certain of its subsidiaries became a partnership and limited liability companies, respectively, and were subsequently treated as pass through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in our financial statements. As such, our predecessor has provided for the change in legal structure by recording an $86.2 million income tax benefit in 2008 at the time the change in legal structure occurred. This benefit was partially offset by income tax expense of $24.9 million, resulting in a net income tax benefit of $61.3 million for the year ended December 31, 2008. The income tax expense of $6.3 million for the nine months ended September 30, 2009 is related to our predecessor’s remaining taxable entity that was not contributed to us. For the year ended December 31, 2011, the year ended December 31, 2010, and the three months ended September 30, 2009, the income tax expense of $3.3 million, $2.4 million and $0.6 million, respectively, is entirely related to Texas Franchise Tax.

⁽⁵⁾  The 2010 amounts are reflective of general and limited partner interests in net income since closing of our Partnership’s IPO on August 3, 2010. See Note 4 to the consolidated financial statements in Item 8 of this annual report.

⁽⁶⁾  Adjusted EBITDA and distributable cash flow are defined under the heading Adjusted EBITDA and Distributable Cash Flow in Item 7 of this annual report. For reconciliations of Adjusted EBITDA and distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles, see How We Evaluate Our Operations in Item 7 of this annual report.

⁽⁷⁾  Excludes production for Appalachia Midstream acquired on December 29, 2011.

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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context otherwise requires, references in this report to the “Partnership,” “we,” “our,” “us” or like terms, when used in a historical context, refer to the financial results of Chesapeake Midstream Partners, L.L.C. from its inception on September 30, 2009 through the closing date of our initial public offering (“IPO”) on August 3, 2010 and to Chesapeake Midstream Partners, L.P. and its subsidiaries thereafter. Our “predecessor” refers to Chesapeake Midstream Development, L.P. which held substantially all of our assets as well as other midstream assets prior to September 30, 2009. “Chesapeake” refers to Chesapeake Energy Corporation (NYSE: CHK), and, where the context requires, its subsidiaries, and “GIP” refers to Global Infrastructure Partners – A, L.P., and affiliated funds managed by Global Infrastructure Management, LLC, and certain of their respective subsidiaries and affiliates. “Total”, when discussing the upstream joint venture with Chesapeake, refers to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (NYSE: TOT, FP: FP), and when discussing our gas gathering agreement and related matters, refers to Total E&P USA, Inc. and Total Gas & Power North America, Inc., a wholly owned subsidiary of Total S.A.

Overview

We are a growth-oriented publicly-traded Delaware limited partnership formed by Chesapeake and GIP to own, operate, develop and acquire natural gas, natural gas liquids and oil gathering systems and other midstream energy assets. We are principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. We currently operate in Texas, Louisiana, Oklahoma, Kansas, Arkansas, West Virginia and Pennsylvania. We provide gathering, treating and compression services to Chesapeake and Total, our primary customers, and other producers under long-term, fixed-fee contracts.

Initial Public Offering

On August 3, 2010, we completed our IPO of 24,437,500 common units (amount includes 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option on August 3, 2010) at a price of $21.00 per unit. We received gross offering proceeds of approximately $513.2 million less approximately $38.6 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of the contribution agreement, we distributed the approximate $62.4 million of net proceeds from the exercise of the over-allotment option to GIP on August 3, 2010. Upon completion of the IPO, Chesapeake and GIP conveyed to us a 100 percent membership interest in Chesapeake MLP Operating, L.L.C., which owned all of our assets since September 2009.

Acquisitions

Marcellus Acquisition

On December 29, 2011, we acquired from Chesapeake Midstream Development, L.P. (“CMD”), a wholly owned subsidiary of Chesapeake, and certain of its affiliates all of the issued and outstanding common units of Appalachia Midstream Services, L.L.C. (“Appalachia Midstream”) for total consideration, which is subject to a customary post-closing working capital adjustment, of $879.3 million, consisting of 9,791,605 common units and $600.0 million in cash that was financed with a draw on our revolving credit facility. The base purchase price of $879.3 million was increased by $7.3 million due to initial working capital adjustments through December 31, 2011. Through the acquisition of Appalachia Midstream, we operate 100 percent of and own an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 231 miles of gas gathering pipeline in the Marcellus Shale in Pennsylvania and West Virginia. The remaining 53 percent interest in these assets is owned primarily by Statoil ASA (NYSE: STO) (“Statoil”), Anadarko Petroleum Corporation

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(NYSE: APC) (“Anadarko”), Epsilon Energy Ltd. (TSE: EPS) (“Epsilon”), and Mitsui & Co., Ltd. (TYO: 8031) (“Mitsui”). Gross throughput for these assets at December 31, 2011, was just over 1.0 billion cubic feet (“Bcf”) per day (approximately 470 million cubic feet (“Mmcf”) per day net to us). The Partnership’s interest in the gas gathering systems is accounted for as an equity investment and is included in income from unconsolidated affiliates. Appalachia Midstream operates the assets under 15-year fixed fee gathering agreements. The gathering agreements include significant acreage dedications and annual fee redeterminations. In addition, CMD has committed to pay us quarterly any shortfall between the actual EBITDA from these assets and specified quarterly targets, with the quarterly targets adding to a total of $100 million in 2012 and $150 million in 2013.

The results of operations presented and discussed in this annual report include results of operations from Appalachia Midstream for the two-day period from closing of the acquisition on December 29, 2011, through December 31, 2011 in Income from unconsolidated affiliates.

Haynesville Acquisition

On December 21, 2010, we acquired the Springridge gathering system and related facilities from CMD for $500 million. The Springridge gathering system consisted of 226 miles of gathering pipeline primarily located in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, we entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication, annual fee redetermination and a three-year minimum volume commitment.

The acquisition was financed with a draw on our revolving credit facility of approximately $234.0 million plus approximately $266.0 million of cash on hand. The results of operations presented and discussed in this Item 7 include results of operations from the Springridge gathering system for the 10-day period from closing of the acquisition on December 21, 2010, through December 31, 2010 as well as year end December 31, 2011, including associated transaction costs.

Our Operations

Our gathering systems operate in our Barnett Shale region in north-central Texas, our Haynesville Shale region in northwest Louisiana, our Marcellus Shale region in Pennsylvania and West Virginia, and our Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian Basins. We generate the majority of our operating income in our Barnett Shale region, where we service approximately 2,219 wells in the core of the Barnett Shale. Our Springridge gathering system services approximately 220 wells in one of the core areas of the Haynesville Shale. In our Mid-Continent region, we have an enhanced focus on the unconventional resources located in the Colony Granite Wash and Texas Panhandle Granite Wash plays of the Anadarko Basin. In total, our systems consisted of approximately 3,629 miles of gathering pipelines, servicing approximately 4,965 natural gas wells prior to the Appalachia Midstream acquisition on December 29, 2011. For the years ended December 31, 2011 and 2010, our assets gathered approximately 2.2 Bcf and 1.6 Bcf of natural gas per day, respectively. On December 29, 2011, we acquired 100 percent of Appalachia Midstream, which operates 100 percent of and owns an approximate average 47 percent interest in 10 gas gathering systems in the Marcellus Shale. The Marcellus gathering systems service approximately 281 wells in Pennsylvania and West Virginia with gross throughput of just over 1.0 Bcf of natural gas per day (approximately 470 Mmcf per day net to us) at December 31, 2011.

We generated approximately 64 percent of our revenues from our gathering systems in our Barnett Shale region, approximately 20 percent of our revenues from our gathering systems in our Mid-Continent region and approximately 16 percent of our revenues from our gathering systems in our Haynesville region for the year ended December 31, 2011. The Marcellus gathering system contributed to our income during the 2-day period from closing of the acquisition to December 31, 2011, but the impact was immaterial to our results.

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The results of our operations are primarily driven by the volumes of natural gas we gather, treat and compress across our gathering systems. We currently provide all of our gathering, treating and compression services pursuant to fixed fee contracts, which limit our direct commodity price exposure, and we generally do not take title to the natural gas we gather. We have entered into long-term gas gathering agreements with Chesapeake, Total, Statoil, Anadarko, Epsilon, Mitsui, Chief Oil & Gas (“Chief”) and other producers. Pursuant to our gas gathering agreements, Chesapeake, Total, Statoil, Anadarko, Epsilon, Mitsui, Chief and other producers have agreed to dedicate extensive acreage in our operating regions. These agreements generally give us the opportunity to connect operated natural gas drilling pads and wells within our acreage dedications to our gathering systems and contain the following terms that are intended to support the stability of our cash flows: (i) minimum volume commitments for 10 years in our Barnett Shale region and three years in our Haynesville Shale region, which mitigate throughput volume variability; (ii) fee redetermination mechanisms in our Barnett Shale, Haynesville Shale, Marcellus Shale and Mid-Continent regions, which are designed to support a return on our invested capital and allow our gathering rates to be adjusted, subject to specified caps in certain cases, to account for variability in revenues, capital expenditures and compression expenses; and (iii) price escalators in our Barnett Shale, Haynesville Shale and Mid-Continent regions, which annually increase our gathering rates.

Our Gas Gathering Agreements

We generate substantially all of our revenues through long-term, fixed-fee natural gas gathering, treating and compression contracts that limit our direct commodity price exposure. We are party to (i) a 20-year gas gathering agreement with respect to the Barnett Shale and the Mid-Continent region with certain subsidiaries of Chesapeake that was entered into in connection with the creation of our predecessor in September 2009, (ii) a 20-year gas gathering agreement with respect to the Barnett Shale with Total that was entered into in connection with an upstream joint venture transaction between Chesapeake and Total E&P in January 2010, (iii) a 10-year gas gathering agreement with certain subsidiaries of Chesapeake that was entered into concurrent with the closing of our acquisition of the Springridge gas gathering system in the Haynesville Shale in December 2010 and (iv) through Appalachia Midstream, 15-year gas gathering agreements with certain subsidiaries of Chesapeake, Statoil, Anadarko, Epsilon, Mitsui and Chief that we acquired in connection with our acquisition of Appalachia Midstream in December 2011.

Future revenues under our gas gathering agreements will be derived pursuant to terms that will vary depending on the applicable operating region. The following outlines the key economic provisions of our gas gathering agreements by region.

Barnett Shale Region.  Under our gas gathering agreements with Chesapeake and Total, we have agreed to provide the following services in our Barnett Shale region for the fees and obligations outlined below:

• Gathering, Treating and Compression Services.  We gather, treat and compress natural gas for Chesapeake and Total within the Barnett Shale region in exchange for specified fees per thousand cubic feet (“Mcf”) for natural gas gathered on our gathering systems that are based on the pressure at the various points where our gathering systems received our customers’ natural gas. We refer to these fees collectively as the Barnett Shale fee. Our Barnett Shale fee is subject to an annual rate escalation of two percent at the beginning of each year.

• Acreage Dedication.  Pursuant to our gas gathering agreements, subject to certain exceptions, each of Chesapeake and Total has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on natural gas and oil leases covering lands within an acreage dedication in our Barnett Shale region.

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• Minimum Volume Commitments.  Pursuant to our gas gathering agreements, Chesapeake and Total have agreed to minimum volume commitments for each year through December 31, 2018 and for the six-month period ending June 30, 2019. Approximately 75 percent of the aggregate minimum volume commitment is attributed to Chesapeake, and approximately 25 percent is attributed to Total. The minimum volume commitments increase, on average, approximately 3 percent per year. The following table outlines the approximate aggregate minimum volume commitments for each year during the minimum volume commitment period:

⁽¹⁾ Indicated volumes relate to the six months ending June 30, 2019.

If either Chesapeake or Total does not meet its minimum volume commitment to us, as adjusted in certain instances, for any annual period (or six-month period in the case of the six months ending June 30, 2019) during the minimum volume commitment period, Chesapeake or Total, as applicable, will be obligated to pay us a fee equal to the Barnett Shale fee for each Mcf by which the applicable party’s minimum volume commitment for the year (or six-month period) exceeds the actual volumes gathered on our systems attributable to the applicable party’s production. To the extent natural gas gathered on our systems from Chesapeake or Total, as applicable, during any annual period (or six-month period) exceeds such party’s minimum volume commitment for the period, Chesapeake or Total, as applicable, will be obligated to pay us the Barnett Shale fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitments for the six months ending June 30, 2019, and then against the minimum volume commitments of each preceding year. If the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the final day of the immediately preceding period.

• Fee Redetermination.  We and each of Chesapeake and Total, as applicable, have the right to request a redetermination of the Barnett Shale fee during a six-month period beginning September 30, 2011 and a two-year period beginning on September 30, 2014. On September 30, 2011, we entered the initial redetermination period and are currently working with Chesapeake to determine whether a fee adjustment is required. The fee redetermination mechanism is intended to support a return on our invested capital. If a fee redetermination is requested, we will determine an adjustment (upward or downward) to our Barnett Shale fee with

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Chesapeake and Total based on the factors specified in our gas gathering agreements, including, but not limited to: (i) differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the minimum volume commitment period made as of September 30, 2009 and (ii) differences between the revised estimates of our capital expenditures, compression expenses and revenues for the remainder of the minimum volume commitment period forecast as of the redetermination date and scheduled estimates thereof for the minimum volume commitment period made as of September 30, 2009. The cumulative upward or downward adjustment for the Barnett Shale region is capped at 27.5 percent of the initial weighted average Barnett Shale fee (as escalated) as specified in the gas gathering agreement. If we and Chesapeake or Total, as applicable, do not agree upon a redetermination of the Barnett Shale fee within 30 days of receipt of the request for the redetermination, an industry expert will be selected to determine adjustments to the Barnett Shale fee.

• Well Connection Requirement.  Subject to required notice by Chesapeake and Total and certain exceptions, we have generally agreed to connect new operated drilling pads and new operated wells within our Barnett Shale region acreage dedications as requested by Chesapeake and Total during the minimum volume commitment period. During the minimum volume period, if we fail to complete a connection in the acreage dedication by the required date, Chesapeake and Total, as their sole remedy for such delayed connection, are entitled to a delay in the minimum volume obligations for gas volumes that would have been produced from the delayed connection.

• Fuel and Lost and Unaccounted For Gas.  We have agreed with Chesapeake and Total on caps on fuel and lost and unaccounted for gas on our systems, both on an individual basis and an aggregate basis, with respect to Chesapeake’s and Total’s volumes. These caps do not apply to certain of our gathering systems due to their historic performance relative to the caps. These systems will be reviewed annually to determine whether changes have occurred that would make them suitable for inclusion. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel and lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

Haynesville Shale Region.  Under our gas gathering agreement with Chesapeake, we have agreed to provide the following services in our Haynesville Shale region to Chesapeake for the fees and obligations outlined below:

• Gathering, Treating and Compression Services.  We gather, treat and compress natural gas in exchange for fees per Mcf for natural gas gathered and per Mcf for natural gas compressed, which we refer to as the Springridge fees. The Springridge fees for these systems are subject to an annual specified rate escalation at the beginning of each year.

• Minimum Volume Commitments.  Pursuant to our gas gathering agreement, Chesapeake has agreed to minimum volume commitments for each year through December 31, 2013. In the event Chesapeake does not meet its minimum volume commitment to us, as adjusted in certain instances, for any annual period during the minimum volume commitment period, Chesapeake will be obligated to pay us a fee equal to the Springridge fee for each Mcf by which the minimum volume commitment for the year exceeds the actual volumes gathered on our systems attributable to Chesapeake’s production. To the extent natural gas gathered on our systems from Chesapeake during any annual period exceeds Chesapeake’s minimum volume commitment for the period, Chesapeake will be obligated to pay us the Springridge fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitments for the year 2013, and then against the minimum volume

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commitments of each preceding year. In the event that the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the final day of the immediately preceding period.

• Acreage Dedication.  Pursuant to our gas gathering agreement, subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on oil, natural gas and mineral leases within the Springridge acreage dedication.

• Fee Redetermination.  The Springridge fees are subject to a redetermination mechanism. The first redetermination period will extend from December 1, 2010 through December 31, 2012, and subsequent redetermination periods will be the calendar years 2013 through 2020. We will determine an adjustment to fees for the gathering systems in the region with Chesapeake based on the factors specified in the gas gathering agreement, including, but not limited to, differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the period ending December 31, 2020, referred to as the redetermination period, made as of November 30, 2010. The annual upward or downward fee adjustment for the Springridge region is capped at 15 percent of the then current fees at the time of redetermination.

• Well Connection Requirement.  We have certain connection obligations for new operated drilling pads and operated wells of Chesapeake in the acreage dedications. Chesapeake is required to provide us notice of new drilling pads and wells operated by Chesapeake in the acreage dedications. Subject to certain conditions specified in the gas gathering agreement, we are generally required to connect new operated drilling pads in the acreage dedication by the later of 30 days after the date the wells commence production or six months after the date of the connection notice. During the minimum volume period, if we fail to complete a connection in the Springridge acreage dedication by the required date, Chesapeake, as its sole remedy for such delayed connection, is entitled to a delay in the minimum volume obligations for gas volumes that would have been produced from the delayed connection. After the minimum volume period, we are subject to a daily penalty for such delayed connections, up to a specified cap per delayed connection. Chesapeake also is required to

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notify us of its wells drilled in the acreage dedications that are operated by other parties and we have the option, but not the obligation, to connect non-operated wells to our gathering systems. If we decline to make a connection to a non-operated well, Chesapeake has certain rights to have the well released from the dedication under the gas gathering agreement.

• Fuel and Lost and Unaccounted For Gas.  We have agreed with Chesapeake on caps on fuel and lost and unaccounted for gas on our systems with respect to Chesapeake’s volumes. These caps do not apply to one of our compressor stations due to its historical performance relative to the caps. This station will be reviewed periodically to determine whether changes have occurred that would make it suitable for inclusion. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.

Marcellus Shale Region.   Under gas gathering agreements between Appalachia Midstream and certain subsidiaries of Chesapeake, Statoil, Anadarko, Epsilon, Mitsui and Chief, we have agreed to provide the following services in our Marcellus Shale region for our proportionate share (based on our ownership interest in the applicable systems) of the fees and obligations outlined below:

• Gathering and Compression Services.  We gather and compress natural gas in exchange for fees per million British thermal units (“MMBtu”) for natural gas gathered and per MMBtu for natural gas compressed. The gathering fees are redetermined annually, as described below. The compression fees escalate on January 1 of each year based on the consumer price index. In addition, CMD has committed to pay us quarterly any shortfall between the actual EBITDA from these assets and specified quarterly targets. The targets add to a total of $100 million in 2012 and $150 million in 2013. These amounts represent the minimum amount of EBITDA we will recognize in each year with the potential that throughput for these systems would generate EBITDA in excess of the guaranteed amounts. The following table outlines the EBITDA commitments for each quarter during the commitment period:

• Acreage Dedication.  Pursuant to our gas gathering agreements, subject to certain exceptions, the shippers and producers have agreed to dedicate all of the natural gas owned

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or controlled by them and produced from or attributable to existing and future wells with a surface location within the designated dedicated areas.

• Fee Redetermination.  Each January 1, gathering fees for each gathering system under the gas gathering agreements with Chesapeake, Statoil, Anadarko, Epsilon and Mitsui are redetermined and adjusted based on the factors specified in the gas gathering agreements, including our capital expenditures for the system, the total revenues and total expenses for the system and the targeted pre-income tax rate of return on capital invested. There is no cap on these fee adjustments. Each January 1, gathering fees for each gathering system under the gas gathering agreement with Chief are adjusted based on the applicable producer price index. The change in the amount of the gathering fees under the Chief agreement is not to exceed 3 percent in any one year.

• Well Connections.  We have the option to connect to new wells within the dedicated acreage. If we elect not to connect to any new well within the dedicated acreage, the shipper for such well may elect to have such well, and any subsequent wells within a two-mile radius (in the case of Chesapeake, Statoil, Anadarko, Epsilon and Mitsui) or a one-mile radius (in the case of Chief) of the surface location of such well, permanently released from the dedication area, or the shipper may elect to construct, at the shipper’s expense, a gathering system to connect to such well (and wells within a one-mile radius of such well in the case of Chesapeake, Statoil, Anadarko, Epsilon and Mitsui), in which case the shipper would pay us a reduced gathering fee for natural gas we receive through the shipper-installed asset. Alternatively, the shipper may require us to enter into an agreement pursuant to which we would construct the gathering system to connect to the well in exchange for a reimbursement by the shipper of the costs we incur in connection therewith. The shipper may elect to connect wells outside the dedicated area at its sole expense and pay us a reduced gathering fee for natural gas we receive from such wells, but gas from such outside wells will not be afforded the same priority as gas produced from wells located within the dedicated area.

• Fuel and Lost and Unaccounted For Gas.  Under our gas gathering agreements with Chesapeake, Statoil, Anadarko, Epsilon and Mitsui, we have agreed on caps on fuel and lost and unaccounted for gas on the systems. If we exceed the permitted cap, we must provide a cost estimate for a remedy that is reasonably expected to prevent exceeding the permitted cap in the future. At the election of the shippers we may pay such costs (which costs would then be included in the gathering fee redetermination) or the shippers may pay the costs. If we exceed the permitted cap and do not provide a proposal to the shippers to prevent exceeding the cap in the future within the required time period, we may incur our proportionate share (based on our ownership interest in the applicable system) of significant fees in connection with the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this may subject us to direct commodity price risk.

Under gas gathering agreements between Appalachia Midstream and certain subsidiaries of Chief, the shipper on each system is to furnish to us, at the shipper’s sole cost and expense, all necessary fuel gas to operate the system. Gas volumes lost solely due to our actions or inactions constituting gross negligence or willful misconduct are our sole responsibility. Additionally, we will bear the cost of natural gas lost in excess of one percent due to our failure to maintain adequate corrosion protection. If we lose natural gas due to our gross negligence or willful misconduct or our failure to maintain an adequate corrosion protection system, we may incur significant expenses in connection with the cost of the lost natural gas. Our responsibility for the cost of the lost gas may subject us to direct commodity price risk.

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Mid-Continent Region.   Under our gas gathering agreement with Chesapeake, we have agreed to provide the following services in our Mid-Continent region to Chesapeake for the fees and obligations of Chesapeake outlined below:

• Gathering, Treating and Compression Services.  We gather, treat and compress natural gas in exchange for system-based services fees per Mcf for natural gas gathered and per Mcf for natural gas compressed. We refer to the fees collectively as the Mid-Continent fee. The Mid-Continent fees for these systems are subject to an annual two and a half percent rate escalation at the beginning of each year.

• Acreage Dedication.  Pursuant to our gas gathering agreement, subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on oil, natural gas and mineral leases covering lands within the acreage dedication.

• Fee Redetermination.  The Mid-Continent fees are redetermined at the beginning of each year through 2019. We and Chesapeake will determine an adjustment to fees for the gathering systems in the region with Chesapeake based on the factors specified in the gas gathering agreement, including, but not limited to, differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the period ending June 30, 2019, referred to as the redetermination period, made as of September 30, 2009. The annual upward or downward fee adjustment for the Mid-Continent region is capped at 15 percent of the then current fees at the time of redetermination.

• Well Connection Requirement.  Subject to required notice by Chesapeake and certain exceptions, we have generally agreed to use our commercially reasonable efforts to connect new operated drilling pads and new operated wells in our Mid-Continent region acreage dedications as requested by Chesapeake through June 30, 2019.

• Fuel and Lost and Unaccounted For Gas.  We have agreed with Chesapeake on caps on fuel and lost and unaccounted for gas on our systems, both on an individual basis and an aggregate basis, with respect to Chesapeake’s volumes. These caps do not apply to certain of our gathering systems due to their historic performance relative to the caps. These systems will be reviewed annually to determine whether changes have occurred that would make them suitable for inclusion. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

We believe the recent trend of producers moving drilling rigs from dry gas regions to liquids rich plays such as the Mid-Continent may present an opportunity for us to enter the market of gathering and transporting oil as we believe those services fit well with our current business model.

If one of the counterparties to the gas gathering agreements sells, transfers or otherwise disposes to a third party properties within the Partnership’s acreage dedications, it will be required to cause the third party to either enter into the existing gas gathering agreement or enter into a new gas gathering agreement with the Partnership on substantially similar terms to the existing gas gathering agreement with the applicable party.

Other Arrangements

Business Opportunities.  Pursuant to our services agreement with Chesapeake, Chesapeake has agreed to provide us a right of first offer with respect to three specified categories of transactions: (i) opportunities to develop or invest in midstream energy projects within five miles of our acreage

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dedications in the Barnett Shale and Mid-Continent regions, (ii) opportunities to succeed third parties in expiring midstream energy service contracts within five miles of the acreage dedications in the Barnett Shale and Mid-Continent regions and (iii) opportunities with respect to future midstream divestitures outside of the acreage dedications. The consummation, if any, and timing of any such future transactions will depend upon, among other things, our ability to reach an agreement with Chesapeake and our ability to obtain financing on acceptable terms. Notwithstanding the foregoing, Chesapeake is under no obligation to accept any offer made by us with respect to such opportunities. Although we will have certain rights with respect to the potential business opportunities, we are not under any contractual obligation to pursue any such transactions. Chesapeake and its affiliates will not be required to provide us with a right of first offer with respect to the following types of transactions:

• equity financing transactions by Chesapeake in respect of any midstream gathering systems and/or associated infrastructure located outside of the acreage dedications and the proximate areas, the net proceeds of which are used to finance the construction, development and/or operation of such midstream gathering systems and/or associated infrastructure assets;

• any financing transactions consisting of debt that is non-convertible and non-exchangeable, provided that any such transaction or series of related transactions may include the issuance of equity interests to the parties providing financing or affiliates thereof that in the aggregate constitute less than 20 percent of the aggregate value of such financing transaction;

• any transactions that would result in a change of control of Chesapeake Energy or a sale of all or substantially all of the assets of Chesapeake and its subsidiaries, taken as a whole;

• any sale, joint venture or other monetization of any midstream gathering system and/or associated infrastructure assets outside the acreage dedications and the proximate areas in connection with a sale of interests in oil and gas properties (including, but not limited to, volumetric production payments) in which the majority of the assets (by value) are comprised of oil and gas exploration and production assets;

• any transaction that was subject to a right of first refusal, purchase or similar commitment to a third party as of September 30, 2009;

• any exchange, swap or similar property-for-property transaction involving the exchange of any midstream gathering system and/or associated infrastructure assets outside the acreage dedications and the proximate areas for other midstream gathering systems and/or associated infrastructure assets outside the acreage dedications and the proximate areas, to the extent any net cash proceeds to Chesapeake from any such transaction or series of related transactions does not comprise more than 20 percent of the aggregate value of the assets subject to such transaction or series of related transactions; and

• any sale, transfer or disposition to a 100 percent affiliate of Chesapeake that remains a 100 percent affiliate of Chesapeake at all times following such sale, transfer or disposition.

Services Arrangements.   Under our services agreement with Chesapeake, Chesapeake has agreed to provide us with certain general and administrative services and any additional services we may request. We reimburse Chesapeake for such general and administrative services in any given month subject to a cap equal to $0.03065 per Mcf multiplied by the volume (measured in Mcf) of natural gas that we gather, treat or compress. The fee is calculated as the lesser of $0.03065 per Mcf gathered or actual corporate overhead costs, excluding those overhead costs that are billed directly to the Partnership. The $0.03065 per Mcf cap is subject to an annual upward adjustment on October 1 of each year equal to 50 percent of any increase in the Consumer Price Index, and, subject to receipt of requisite approvals, such cap may be further adjusted to reflect changes in general and administrative services provided by Chesapeake relating to new laws or accounting rules that are implemented. The cap contained in the services agreement does not apply to our direct general and administrative expenses.

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Additionally, pursuant to an employee secondment agreement, specified employees of Chesapeake are seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Our general partner, subject to specified exceptions and limitations, reimburses Chesapeake on a monthly basis for substantially all costs and expenses it incurs relating to such seconded employees. Additionally, under our employee transfer agreement, we are required to maintain certain compensation standards for seconded employees to whom we make offers for hire.

How We Evaluate Our Operations

Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (i) throughput volumes, (ii) revenues, (iii) operating expenses, (iv) Adjusted EBITDA and (v) distributable cash flow.

Throughput Volumes

Although Chesapeake’s and Total’s respective minimum volume commitments generally provide us with protection if throughput volumes from Chesapeake or Total in the Barnett Shale region and Chesapeake in the Haynesville Shale region do not meet certain levels, our management analyzes our performance based on the aggregate amount of throughput volumes on our gathering systems in our Barnett Shale, Haynesville Shale, Marcellus Shale and Mid-Continent regions in order to maintain or increase throughput volumes on our gathering systems as a whole. Our success in connecting additional wells is impacted by successful drilling activity on the acreage dedicated to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage, our ability to attract natural gas volumes currently gathered by our competitors and our ability to cost-effectively construct new infrastructure to connect new wells.

Revenues

Our revenues are driven primarily by our customers’ minimum volume commitments and the actual volumes of natural gas we gather, treat and compress. Our volumes will be supported by the minimum volume commitments contained in our gas gathering agreements with Chesapeake and Total in the case of our Barnett Shale and Chesapeake in the case of our Haynesville Shale. We contract with producers to gather natural gas from individual wells located near our gathering systems. We connect wells to gathering pipelines through which natural gas is compressed and may be delivered to a treating facility, processing plant or an intrastate or interstate pipeline for delivery to market. We treat natural gas that we gather to the extent necessary to meet required specifications of third-party takeaway pipelines. For the years ended December 31, 2011 and 2010, Chesapeake accounted for approximately 84 percent and 81 percent, respectively, of the natural gas volumes on our gathering systems and 83 percent and 82 percent, respectively, of our revenues.

Our revenues are also impacted by other aspects of our contractual agreements, including rate redetermination, and our management constantly evaluates capital spending and its impact on future revenue generation.

Operating Expenses

Our management seeks to maximize the profitability of our operations by minimizing operating expenses without compromising environmental protection and employee safety. Operating expenses are comprised primarily of field operating costs (which include labor, treating and chemicals, and

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measurements services among other items), compression expense, ad valorem and taxes and other operating costs, some of which are independent of the volumes that flow through our systems but fluctuate depending on the scale of our operations during a specific period.

Chesapeake has extensive operational, commercial, technical and administrative personnel that we plan to utilize to enhance our operating efficiency and overall asset utilization. In some instances, these services are available to us at a low cost compared to the expense of developing these functions internally.

Adjusted EBITDA and Distributable Cash Flow

We define Adjusted EBITDA as net income (loss) before income tax expense (benefit), interest expense, depreciation and amortization expense and certain other items management believes effect the comparability of operating results.

We define distributable cash flow as Adjusted EBITDA, plus interest income, less cash paid for interest expense, maintenance capital expenditures and income taxes. Distributable cash flow does not reflect changes in working capital balances. Distributable cash flow and Adjusted EBITDA are not presentations made in accordance with generally accepted accounting principles (“GAAP”).

We did not utilize a distributable cash flow measure prior to becoming a publicly traded partnership in 2010 and, as such, did not differentiate between maintenance and capital expenditures prior to 2010 and do not report distributable cash flow for periods prior to 2010.

Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

• our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis, or in the case of Adjusted EBITDA, financing methods;

• our ability to incur and service debt and fund capital expenditures;

• the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and

• the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

Reconciliation to GAAP measures

We believe that the presentation of Adjusted EBITDA and distributable cash flow provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and distributable cash flow are presented because they are helpful to management, industry analysts, investors, lenders and rating agencies and may be used to assess the financial performance and operating results of our fundamental business activities. The GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow are net income and net cash provided by operating activities. Our non-GAAP financial measures of Adjusted EBITDA and distributable cash flow should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Each of Adjusted EBITDA and distributable cash flow has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. You should not consider either Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted

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EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

The following table presents a reconciliation of the non-GAAP financial measures of Adjusted EBITDA and distributable cash flow to the GAAP financial measures of net income and net cash provided by operating activities:

									Predecessor
	Year Ended December 31, 2011			Year Ended December 31, 2010			Three Months Ended December 31, 2009		Nine Months Ended September 30, 2009
				($ in thousands)
Reconciliation of Adjusted EBITDA and Distributable cash flow to net income:
Net income (loss)	$	194,337		$	195,227		$	50,692	$	(17,374	)
Interest expense		14,884			7,426			619		347
Income tax expense		3,289			2,431			639		6,341
Depreciation and amortization expense		136,169			88,601			20,699		65,477
Impairment of property, plant and equipment and other assets		—			—			—		90,207
Loss on sale of assets		739			285			34		44,566
Income from unconsolidated affiliates		(433	)		—			—		—
EBITDA from unconsolidated affiliates		488			—			—		—
Adjusted EBITDA	$	349,473		$	293,970		$	72,683	$	189,564
Maintenance capital expenditures		(74,000	)		(70,000	)		n/a		n/a
Cash portion of interest expense		(10,224	)		(2,550	)		n/a		n/a
Income tax expense		(3,289	)		(2,431	)		n/a		n/a
Distributable cash flow(1)	$	261,960		$	218,989			n/a		n/a
									Predecessor
	Year Ended December 31, 2011			Year Ended December 31, 2010			Three Months Ended December 31, 2009		Nine Months Ended September 30, 2009
				($ in thousands)
Reconciliation of Adjusted EBITDA and Distributable cash flow to net cash provided by operating activities:
Net cash provided by operating activities	$	399,016		$	317,091		$	14,730	$	100,748
Changes in assets and liabilities		(62,457	)		(28,002	)		56,656		88,187
Interest expense		14,884			7,426			619		347
Current income tax expense		3,289			2,431			639		—
Other non-cash items		(5,747	)		(4,976	)		39		282
EBITDA from unconsolidated affiliates		488			—			—		—
Adjusted EBITDA	$	349,473		$	293,970		$	72,683	$	189,564
Maintenance capital expenditures		(74,000	)		(70,000	)		n/a		n/a
Cash portion of interest expense		(10,224	)		(2,550	)		n/a		n/a
Income tax expense		(3,289	)		(2,431	)		n/a		n/a
Distributable cash flow(1)	$	261,960		$	218,989			n/a		n/a

⁽¹⁾ We did not utilize a distributable cash flow measure prior to becoming a publicly traded partnership in 2010 and, as such, did not differentiate between maintenance and capital expenditures prior to 2010 and do not report distributable cash flow for periods prior to 2010.

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Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to the historical results of operations for the periods presented for our predecessor, for the reasons described below:

• The historical consolidated financial statements of our predecessor cover periods in which our assets experienced significant growth. Due to the significant build-out of our gathering systems, capital expenditures by our predecessor for historical periods presented in the unaudited condensed consolidated financial statements in Part II, Item 8 of this Form 10-K were higher than those we have experienced since September 30, 2009.

• Our predecessor incurred impairments of property, plant and equipment and other assets of $30.0 million and $90.2 million for the year ended December 31, 2008, and the nine months ended September 30, 2009, respectively.

• We are incurring approximately $2.0 million annually of general and administrative expenses attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange (the “NYSE”); independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and director compensation. These incremental general and administrative expenses are not reflected in the historical consolidated financial statements of our predecessor.

• We have entered into gas gathering agreements with each of Chesapeake, Total and other producers that include fees for gathering, treating and compressing natural gas that are higher than the average fees reflected in our predecessor’s historical financial results prior to September 30, 2009. In addition, the financial statements subsequent to September 30, 2009, contain revenue associated with minimum volume commitments that did not impact periods prior to September 30, 2009.

• Our predecessor’s historical consolidated financial statements include U.S. federal and state income tax expense. Due to our status as a partnership, we are not subject to U.S. federal income tax and certain state income taxes.

• We paid a prorated distribution following the quarter ending September 30, 2010, covering the period from the closing of our IPO through September 30, 2010, and paid a quarterly distribution for each subsequent quarterly period. Based on the terms of our cash distribution policy, we expect that we will distribute quarterly to our unitholders and our general partner most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations that is not distributed to our unitholders and our general partner, borrowings under our revolving credit facility and future issuances of equity and debt securities. Historically, our predecessor largely relied on internally generated cash flows and capital contributions from Chesapeake to satisfy its capital expenditure requirements.

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Results of Operations

The results of our operations and those of our predecessor are not comparable. Please see “-Items Impacting the Comparability of Our Financial Results in this Item 7. In this discussion, we have presented the factors that materially affected our operating results for the three months ended December 31, 2009 and our predecessor’s operating results for the nine months ended September 30, 2009. A comparative discussion of the results of operations of these periods has not been provided due to the lack of a comparable data for these operating periods. We have provided a detailed comparison for the years ended December 31, 2011 and 2010 which is included in the chart and discussion below. The following table and discussion present a summary of our and our predecessor’s financial results of operations for the periods described above:

										Predecessor
	Year Ended December 31, 2011			Year Ended December 31, 2010			Three Months Ended December 31, 2009			Nine Months Ended September 30, 2009
	($ in thousands, except per unit data)
Revenues, including revenue from Affiliates(1)	$	565,929		$	459,153		$	107,377		$	358,921
Operating expenses, including expenses from affiliates		176,851			133,293			31,874			146,604
Depreciation and amortization expense		136,169			88,601			20,699			65,477
General and administrative expense, including expenses from affiliates		40,380			31,992			2,854			22,782
Impairment of property, plant and equipment and other assets		—			—			—			90,207
Loss on sale of assets		739			285			34			44,566
Total operating expenses		354,139			254,171			55,461			369,636
Operating income (loss)		211,790			204,982			51,916			(10,715	)
Income from unconsolidated affiliates		433			—			—			—
Interest expense		(14,884	)		(7,426	)		(619	)		(347	)
Other income		287			102			34			29
Income (loss) before income tax expense		197,626			197,658			51,331			(11,033	)
Income tax expense (benefit)		3,289			2,431			639			6,341
Net income (loss)	$	194,337		$	195,227		$	50,692		$	(17,374	)
Operating Data:
Throughput, Bcf/d(2)		2.176			1.595			1.550			2.108

⁽¹⁾  If either Chesapeake or Total does not meet its minimum volume commitment to the Partnership in the Barnett Shale region or Chesapeake does not meet its minimum volume commitment in the Haynesville Shale region under the applicable gas gathering agreement for specified annual periods, Chesapeake or Total is obligated to pay the Partnership a fee equal to the applicable fee for each Mcf by which the applicable party’s minimum volume commitment for the year exceeds the actual volumes gathered on the Partnership’s systems. The Partnership recognizes any associated revenue in the fourth quarter. Our revenues for the three months ended December 31, 2009 includes the impact of $7.7 million attributable to Chesapeake associated with the minimum volume commitment in our Barnett Shale region for 2009. For the years ended December 31, 2011 and 2010, we recognized revenue related to volume shortfall of $17.4 million and $56.8 million, respectively, because throughput in our Barnett Shale region was below contractual minimum volume commitment levels.

⁽²⁾  Excludes production for Appalachia Midstream acquired on December 29, 2011.

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Year Ended December 31, 2011 vs. Year Ended December 31, 2010

Revenues.  Our revenues are primarily attributable to the amount of throughput on our gathering systems and the rates charged for gathering such throughput. For the years ended December 31, 2011 and 2010, our throughput was 2.2 Bcf per day and 1.6 Bcf per day, respectively. The increase in our throughput was primarily due to the acquisition of Springridge at the end of 2010. Revenues were $565.9 million and $459.2 million, respectively, an increase of 23.2 percent. Revenues were positively impacted by the redetermination of Mid-Continent gathering rates that occurred on January 1, 2011, increasing gathering rates in that region by approximately 15 percent. Gathering rates increased two percent in the Barnett Shale and two and a half percent in the Mid-Continent region as a result of annual contractual rate increases. We also benefited from added compression revenues during 2011 as well as additional revenues resulting from the significant number of well connects completed during the year. For the years ended December 31, 2011 and 2010, we connected 610 and 427 new wells, respectively.

Because throughput in the Barnett Shale during 2011 and 2010 was below contractual minimum volume commitment levels, we recognized revenue related to volume shortfall of $17.4 million and $56.8 million for the years ended December 31, 2011 and 2010, respectively. The amount recognized in 2010 included a one-time carry forward from 2009 of $17.2 million. The minimum volume commitment is measured annually and recognized in the fourth quarter of each year.

The table below reflects revenues and throughput by region for the year ended December 31, 2011 compared to the year ended December 31, 2010:

	Years Ended December 31,				% Change(1)
	2011		2010
	(In thousands, except percentages and throughput data)
Revenue:
Barnett Shale	$	361,843	$	358,821		0.8	%
Haynesville Shale		93,107		2,082		N.M.
Mid-Continent		110,979		98,250		13.0
	$	565,929	$	459,153		23.3
Throughput (Bcf):
Barnett Shale		395.4		374.0		5.7	%
Haynesville Shale		197.5		4.9		N.M.
Mid-Continent		201.4		203.4		(1.0	)
		794.3		582.3		36.4

⁽¹⁾  N.M.—not meaningful

Operating Expenses.  Operating expenses were $0.22 per Mcf for year ended December 31, 2011 compared to $0.23 per Mcf for year ended December 31, 2010. Despite the overall decrease, we have experienced an increase in both the Barnett Shale and Mid-Continent regions due to additional compression expense that has increased our overall throughput capacity and associated revenue. We have also incurred increased expenses for additional field personnel and other personnel related costs resulting from Partnership growth.

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The table below reflects our total operating expenses and operating expenses per Mcf of throughput by region for the year ended December 31, 2011 compared to the year ended December 31, 2010:

	Years Ended December 31,				% Change(1)
	2011		2010
	(In thousands, except percentages and per Mcf data)
Operating Expenses:
Barnett Shale	$	102,987	$	86,927		18.5	%
Haynesville Shale		20,277		508		N.M.
Mid-Continent		53,587		45,858		16.9
	$	176,851	$	133,293		32.7
Expenses ($ per Mcf):
Barnett Shale	$	0.26	$	0.23		13.0	%
Haynesville Shale		0.10		0.10		N.M.
Mid-Continent		0.27		0.23		17.4
	$	0.22	$	0.23		(4.3	)

⁽¹⁾  N.M.—not meaningful

Depreciation and Amortization Expense.  Depreciation expense for the year ended December 31, 2011 increased 41.0 percent to $124.9 million from $88.6 million for the year ended December 31, 2010. Amortization expense for the year ended December 31, 2011 was $11.3 million. The increase in depreciation and amortization is a result of capital expenditures made in 2010 and early 2011 and the acquisition of the Springridge gathering system in the Haynesville Shale at the end of 2010.

General and Administrative Expense.  For the years ended December 31, 2011 and 2010, general and administrative expenses were $40.4 million and $32.0 million, respectively, representing an increase of 26.2 percent. The increase is primarily attributable to additional expenses resulting from the acquisition of the Springridge gathering system in the Haynesville Shale.

Interest Expense.  Interest expense for the year ended December 31, 2011 was $14.9 million, which was net of $9.5 million of capitalized interest. Interest expense was $7.4 million for the year ended December 31, 2010, which was net of $2.6 million of capitalized interest. The increase is related to interest expense on the senior notes issued in April 2011. We incur interest expense on our senior notes, borrowings under our revolving credit facility and commitment fees on the unused portion of the credit facility. Interest expense also includes amortization of previously capitalized debt issuance costs.

Income Tax Expense.  Income tax expense for the years ended December 31, 2011 and 2010 was $3.3 million and $2.4 million, respectively, and was attributable to franchise taxes in the state of Texas. The Partnership and its subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the financial statements, other than Texas Franchise Tax.

Income from unconsolidated affiliates.  On December 29, 2011, we acquired all of the issued and outstanding common units of Appalachia Midstream, which owns an approximate average 47 percent interest in 10 gas gathering systems in the Marcellus Shale in Pennsylvania and West Virginia. The remaining 53 percent interest in these assets is owned primarily by Statoil, Anadarko, Epsilon and Mitsui. Income from unconsolidated affiliates was $0.4 million reflecting activity for the last two days of December 2011.

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Three Months Ended December 31, 2009

Revenues.  Our revenues are primarily attributable to the amount of throughput on our gathering systems and the rates charged for gathering such throughput. Revenues for the three months ended December 31, 2009 include $7.7 million attributable to Chesapeake associated with the minimum volume commitment in our Barnett Shale region for 2009. Average daily throughput for the Barnett and Mid-Continent was 1.6 Bcf per day for three months ended December 31, 2009. The table below reflects our revenues and throughput by region for the three months ended December 31, 2009:

	Revenues		Throughput (Bcf)
	(In thousands, except operational data)
Barnett Shale	$	80,880		88.3
Mid-Continent		26,497		54.3
	$	107,377		142.6

Operating Expenses.  Operating expenses for the Barnett and Mid-Continent were $0.22 per Mcf for the three months ended December 31, 2009. The table below reflects our total operating expenses and operating expenses per Mcf of throughput by region for the three months ended December 31, 2009:

	Operating Expenses		Expenses ($ per Mcf)
	(In thousands, except per Mcf data)
Barnett Shale	$	18,638	$	0.21
Mid-Continent		13,236		0.24
	$	31,874	$	0.22

Depreciation and Amortization Expense.  Depreciation and amortization expense for the three months ended December 31, 2009, was $20.7 million and primarily related to gathering systems.

General and Administrative Expense.  During the three months ended December 31, 2009, general and administrative expenses were $2.9 million primarily attributable to costs allocated from Chesapeake related to centralized general and administrative services provided under our agreements with Chesapeake.

Interest Expense.  Interest expense for the three months ended December 31, 2009 was $0.6 million, which was net of $1.8 million of capitalized interest. The interest expense was related to borrowings under our revolving credit facility.

Income Tax Expense (Benefit).  Income tax expense for the three months ended December 31, 2009 was $0.6 million and was attributable to franchise taxes in the state of Texas. The Partnership and its subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the financial statements, other than Texas Franchise Tax.

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Predecessor—Nine Months Ended September 30, 2009

Revenues.  Predecessor’s revenues were $358.9 million with total volumetric throughput of 575 Bcf. The table below reflects our predecessor’s revenues and throughput by region for the predecessor 2009 Period:

	Revenues		Throughput (Bcf)
	(In thousands, except operational data)
Appalachian Basin	$	4,896		10.2
Barnett Shale		201,217		248.1
Fayetteville Shale		52,314		78.8
Haynesville Shale		24,106		60.7
Mid-Continent		76,388		177.6
	$	358,921		575.4

Operating Expenses.  Operating expenses were $146.6 million for the predecessor 2009 Period. The table below reflects our predecessor’s total operating expenses and operating expenses per Mcf of throughput by region for the predecessor 2009 Period:

	Operating Expenses		Expenses ($ per Mcf)
	(In thousands, except per Mcf data)
Appalachian Basin	$	2,819	$	0.28
Barnett Shale		73,505		0.30
Fayetteville Shale		27,509		0.35
Haynesville Shale		5,784		0.10
Mid-Continent		36,987		0.21
	$	146,604	$	0.25

Depreciation and Amortization Expense.  Depreciation and amortization expense was $65.5 million for the predecessor 2009 Period and was primarily related to gathering systems.

General and Administrative Expense.  General and administrative expense was $22.8 million for the predecessor 2009 Period. During this period, our predecessor incurred approximately $3.3 million of charges associated with the completion of the joint venture with GIP.

Impairment of Property, Plant and Equipment and Other Assets.  Impairment of property, plant and equipment and other assets for the predecessor 2009 Period was $90.2 million. Our predecessor recorded an $86.2 million impairment associated with certain gathering systems located in the Mid-Continent region that were not expected to have future cash flows in excess of the book value of these systems. These systems were subsequently contributed to Chesapeake MLP Operating, L.L.C (formerly known as Chesapeake Midstream Partners, L.L.C.). Additionally, $4 million of debt issuance costs were expensed as a result of the amendment of our predecessor’s $460 million credit facility.

Loss on Sale of Assets.  Our predecessor recorded a $44.6 million loss on the sale of certain non-core and non-strategic gathering systems during the predecessor 2009 Period.

Interest Expense.  Interest expense for the predecessor 2009 Period was $0.4 million, which is net of $6.5 million of capitalized interest. The interest expense was related to borrowings under our predecessor’s revolving credit facility that was established in October of 2008.

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Income Tax Expense (Benefit).  Our predecessor recorded income tax expense of $6.3 million for the predecessor 2009 Period. This income tax expense was related to our predecessor’s remaining taxable entity that was not contributed to us and was based on the 37.5 percent effective corporate tax rate of our predecessor.

Liquidity and Capital Resources

Our ability to finance operations and fund capital expenditures will largely depend on our ability to generate sufficient cash flow to cover these expenses as well as the availability of borrowings under our revolving credit facility and our access to the capital markets. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. See Risk Factors in Item 1A of this annual report.

Historically, our sources of liquidity included cash generated from operations and borrowings under our revolving credit facility.

Working Capital.  Working capital, defined as the amount by which current assets exceed current liabilities, is an indication of liquidity and the potential need for short-term funding. As of December 31, 2011 and 2010, we had a working capital deficit of $54.9 million and working capital of $33.5 million, respectively. Working capital decreased from December 31, 2010 to December 31, 2011, primarily as a result of the amount of revenue and receivables recorded for minimum volume commitments at the end of each year. For the years ended December 31, 2011 and 2010, we recognized revenue related to volume shortfall of $17.4 million and $56.8 million, respectively, because throughput in our Barnett Shale region was below contractual minimum volume commitment levels. In addition, accounts payable and accrued liabilities increased approximately $45.1 million year-over-year as a result of timing of payments at each year-end and increased operating activity resulting from the Springridge gathering system acquisition.

Cash Flows.  Net cash provided by (used in) operating activities, investing activities and financing activities of the Partnership for the year ended December 31, 2011 and 2010 were as follows:

	Years Ended December 31,
	2011			2010
	($ in thousands)
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	399,016		$	317,091
Investing activities		(1,017,104	)		(711,480	)
Financing activities		600,294			412,202

Operating Activities.  Net cash provided by operating activities was $399.0 million for the year ended December 31, 2011 compared to $317.1 million for the year ended December 31, 2010. This amount was attributable to both cash flow from operations and changes in working capital. Cash flow from operations increased in 2011 as additional volumes have been brought onto our systems through both capital expenditures and the acquisition of the Haynesville Springridge gathering system in December 2010.

Investing Activities.  Net cash used in investing activities for the year ended December 31, 2011 increased $305.6 million compared to the prior year. Approximately $1.0 billion of cash was used in investing activities during 2011. This amount included approximately $418.8 million in additions to property, plant, and equipment and $600.0 million of cash paid as part of the acquisition of Appalachia Midstream.

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Financing Activities.  Net cash provided by financing activities was $600.3 million for the year ended December 31, 2011 compared to $412.2 million for the year ended December 31, 2010. This change was primarily attributable to the proceeds from the issuance of long-term debt in 2011 that exceeded the proceeds from our IPO in 2010.

Sources of Liquidity.  At December 31, 2011, our sources of liquidity included:

• cash on hand;

• cash generated from operations;

• borrowings under our revolving credit facility; and

• capital raised through debt and equity markets.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to fund our quarterly cash distributions to unitholders.

Credit Facility.  On December 20, 2011, we exercised the accordion option feature under our Amended and Restated Credit Agreement to increase the total revolving commitments from $800 million to $1 billion. Additionally, we amended our Amended and Restated Credit Agreement to, among other things, permit us to make certain investments in Joint Ventures (as defined in the amendment), which Joint Ventures, unless otherwise agreed to by us, will not be subject to the provisions of the revolving credit facility and will not be required to become guarantors under the revolving credit facility. The amendment also provides that we may from time to time request increases in the total revolving commitments under the credit facility up to $1.25 billion, subject to the satisfaction of certain conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the facility. Our revolving credit facility matures in June 2016. As of December 31, 2011 we had $712.9 million of borrowings outstanding under our revolving credit facility.

Borrowings under our revolving credit facility are available to fund working capital, finance capital expenditures and acquisitions, provide for the issuance of letters of credit and for general partnership purposes. Our revolving credit facility is secured by all of our assets, and loans thereunder (other than swing line loans) bear interest at our option at either (i) the greater of (a) the reference rate of Wells Fargo Bank, NA, (b) the federal funds effective rate plus 0.50 percent or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (LIBOR), plus 1.00 percent, each of which is subject to a margin that varies from 0.625 percent to 1.50 percent per annum, according to the Partnership’s leverage ratio (as defined in the agreement), or (ii) the Eurodollar rate plus a margin that varies from 1.625 percent to 2.50 percent per annum, according to the Partnership’s leverage ratio. If we reach investment grade status, we will have the option to release the security under the credit facility and amounts borrowed will bear interest under a specified ratings-based pricing grid. The unused portion of the credit facility is subject to commitment fees of (a) 0.25 percent to 0.40 percent per annum while we are subject to the leverage-based pricing grid, according to the Partnership’s leverage ratio and (b) 0.20 percent to 0.35 percent per annum while we are subject to the ratings-based pricing grid, according to our senior unsecured long-term debt ratings.

Additionally, our revolving credit facility contains various covenants and restrictive provisions which limit our and our subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness. If we fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared

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immediately due and payable. Our revolving credit facility also has cross default provisions that apply to any other indebtedness we may have with an outstanding principal amount in excess of $15 million.

The revolving credit facility agreement contains certain negative covenants that (i) limit our ability, as well as the ability of certain of our subsidiaries, among other things, to enter into hedging arrangements and create liens and (ii) require us to maintain a consolidated leverage ratio, and an EBITDA to interest expense ratio, in each case as described in the credit facility agreement. The revolving credit facility agreement also provides for the discontinuance of the requirement for us to maintain the EBITDA to interest expense ratio if we reach investment grade status. The revolving credit facility agreement requires us to maintain a consolidated leverage ratio of 5.0 to 1.0 (or 5.5 to 1.0 during an approximate two-quarter period following the completion of certain acquisitions). We were in compliance with all covenants under the agreement at December 31, 2011.

Senior Notes.  On January 11, 2012, we and CHKM Finance Corp., a wholly owned subsidiary of Chesapeake MLP Operating, L.L.C., completed a private placement of $750.0 million in aggregate principal amount of 6.125 percent senior notes due 2022 (the “2022 Notes”). We used a portion of the net proceeds to repay all borrowings outstanding under our revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $12.4 million are being amortized over the life of the 2022 Notes.

The 2022 Notes will mature on July 15, 2022 and interest is payable on January 15 and July 15 of each year. We have the option to redeem all or a portion of the 2022 Notes at any time on or after January 15, 2017, at the redemption price specified in the indenture relating to the 2022 Notes, plus accrued and unpaid interest. We may also redeem the 2022 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to January 15, 2017. In addition, we may redeem up to 35 percent of the 2022 Notes prior to January 15, 2015 under certain circumstances with the net cash proceeds from certain equity offerings.

On April 19, 2011, we and CHKM Finance Corp completed a private placement of $350.0 million in aggregate principal amount of 5.875 percent senior notes due 2021 ( the “2021 Notes”). We used a portion of the net proceeds to repay borrowings outstanding under our revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $7.8 million are being amortized over the life of the 2021 Notes.

The 2021 Notes will mature on April 15, 2021 and interest is payable on April 15 and October 15 of each year. We have the option to redeem all or a portion of the 2021 Notes at any time on or after April 15, 2015, at the redemption price specified in the indenture relating to the 2021 Notes, plus accrued and unpaid interest. We may also redeem the 2021 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to April 15, 2015. In addition, we may redeem up to 35 percent of the 2021 Notes prior to April 15, 2014 under certain circumstances with the net cash proceeds from certain equity offerings.

The 2022 Notes and the 2021 Notes indentures contain covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: (1) sell assets including equity interests in its subsidiaries; (2) pay distributions on, redeem or purchase our units, or redeem or purchase our subordinated debt; (3) make investments; (4) incur or guarantee additional indebtedness or issue preferred units; (5) create or incur certain liens; (6) enter into agreements that restrict distributions or other payments from certain subsidiaries to us; (7) consolidate, merge or transfer all or substantially all of our or certain of our subsidiaries’ assets; (8) engage in transactions with affiliates; and (9) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the 2022 Notes or the 2021 Notes achieve an investment grade rating from either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no default, as defined in the indenture, has occurred or is continuing, many of these covenants will terminate.

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Capital Requirements.  Our business is capital-intensive, requiring significant investment to grow our business as well as to maintain and improve existing assets. We categorize capital expenditures as either:

• maintenance capital expenditures, which include those expenditures required to maintain our long-term operating capacity and/or operating income and service capability of our assets, including the replacement of system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives, those expenditures necessary to remain in compliance with regulatory legal requirements or those expenditures necessary to complete additional well connections to maintain existing system volumes and related cash flows; or

• expansion capital expenditures, which include those expenditures incurred in order to acquire additional assets to grow our business, expand and upgrade our systems and facilities, extend the useful lives of our assets, increase gathering, treating and compression throughput from current levels and reduce costs or increase revenues.

For the years ended December 31, 2011 and 2010, expansion capital expenditures totaled $344.8 million and $146.3 million, respectively. Maintenance capital expenditures totaled $74.0 million and $70.0 million for the years ended December 31, 2011 and 2010, respectively, an increase of 5.7 percent. Our 2011 spending was primarily concentrated in our Barnett Shale region. Our future capital expenditures may vary significantly from budgeted amounts and from period to period based on the investment opportunities that become available to us.

We continually review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Because our partnership agreement requires us to distribute most of the cash generated from operations to our unitholders and our general partner, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations that is not distributed to our unitholders and general partner, borrowings under our revolving credit facility and future issuances of equity and debt securities.

We project expansion capital expenditures of $660 million and maintenance capital expenditures of $74 million for the twelve months ended December 31, 2012. We project adjusted EBITDA of $475 million for 2012.

Distributions.  We intend to pay a minimum quarterly distribution of $0.3375 per unit per quarter. We do not have a legal obligation to pay this distribution.

The following table represents a summary of our quarterly distributions for the years end December 31, 2011 and 2010:

	Declaration Date		Record Date		Distribution Date		Distribution Declared
2011
Fourth quarter		January 27, 2012		February 7, 2012		February 14, 2012	$	0.3900
Third quarter		October 28, 2011		November 7, 2011		November 14, 2011		0.3750
Second quarter		July 26, 2011		August 5, 2011		August 12, 2011		0.3625
First quarter		April 26, 2011		May 6, 2011		May 13, 2011		0.3500
2010
Fourth quarter		January 31, 2011		February 10, 2011		February 10, 2011	$	0.3375
Third quarter		October 26, 2010		November 5, 2010		November 12, 2010		0.2165	(1)
Second quarter		n/a		n/a		n/a		n/a
First quarter		n/a		n/a		n/a		n/a

⁽¹⁾  This amount represents a minimum quarterly distribution prorated for the 59-day period beginning on August 3, 2010 and ending on September 30, 2010.

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Contractual Obligations.  At December 31, 2011, our contractual obligations included:

	Payments Due By Period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(in thousands)
Long-term debt (including interest)(1)	$	1,353,446	$	42,670	$	85,340	$	787,187	$	438,249
Operating leases(2)		79,496		36,549		37,901		5,046		—
Total	$	1,432,942	$	79,219	$	123,241	$	792,233	$	438,249

⁽¹⁾  Assumes constant interest rate of 2.94 percent on the outstanding balance of our revolving credit facility and a commitment fee of 0.40 percent on the unused portion of the facility.

⁽²⁾  Includes our contractual obligations for Appalachia Midstream acquired on December 29, 2011.

Application of Critical Accounting Policies

Readers of this report and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. The policies we consider to be the most significant are discussed below. The Partnership’s management has discussed each critical accounting policy with the Audit Committee of the Partnership’s general partner’s board of directors.

The selection and application of accounting policies are an important process that changes as our business changes and as accounting rules are developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment to the specific set of circumstances existing in our business.

Revenue and cost of sales recognition

We estimate certain revenue and expenses since actual amounts are not confirmed until after the financial closing process due to the standard settlement dates in the gas industry. We calculate estimated revenues using actual pricing and measured volumes. In the second month after production, we reverse the accrual and record the actual results. Prior to the settlement date, we record actual operating data to the extent available, such as actual operating and maintenance and other expenses. We do not expect actual results to differ materially from our estimates.

Depreciation and amortization

Depreciation associated with our property, plant and equipment and other assets is calculated using the straight-line method, based on the estimated useful lives of our assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, we and our predecessor make estimates with respect to useful lives and salvage values that we believe and our predecessor believes, respectively, are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation. The estimated service lives of our functional asset groups are as follows:

Asset Group	Estimated Useful Lives (In years)
Gathering systems	20
Other fixed assets	2 to 39

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Intangible assets are generally amortized on a straight-line basis over their estimated useful lives, unless the assets economic benefits are consumed on an other than straight-line basis. The estimated useful life is the period over which the assets are expected to contribute directly or indirectly to the Partnership’s future cash flows.

Impairment of long-lived assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount that the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risks associated with achieving the underlying cash flows.

Recently Issued Accounting Standards

The Financial Accounting Standards Board (“FASB”) recently issued the following standard which we reviewed to determine the potential impact on our financial statements upon adoption.

In December 2010, the FASB issued guidance on disclosure of supplementary pro forma information for business combinations. The guidance specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The guidance also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, non-recurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenues and earnings. These amendments are effective prospectively for business combinations with an acquisition date on or after December 15, 2010.

Forward-Looking Statements

Certain statements and information in this offering memorandum may constitute forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

• dependence on Chesapeake, Total and other producers for a substantial majority of our revenues;

• the impact on our growth strategy and ability to increase cash distributions if Chesapeake, Total or other producers do not increase the volume of natural gas they provide to our gathering systems;

72

• oil and natural gas realized prices;

• the termination of our gas gathering agreements with Chesapeake, Total or other producers;

• the availability, terms and effects of acquisitions from Chesapeake;

• our potential inability to maintain existing distribution amounts or pay the minimum quarterly distribution to our unitholders;

• the limitations that Chesapeake’s and our own level of indebtedness may have on our financial flexibility;

• our ability to obtain new sources of natural gas, which is dependent on factors largely beyond our control;

• the availability of capital resources to fund capital expenditures and other contractual obligations, and our ability to access those resources through the debt or equity capital markets;

• competitive conditions;

• the unavailability of third-party pipelines interconnected to our gathering systems or the potential that the volumes we gather do not meet the quality requirement of such pipelines;

• new asset construction may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks;

• our exposure to direct commodity price risk may increase in the future;

• our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;

• hazards and operational risks that may not be fully covered by insurance;

• our dependence on Chesapeake for substantially all of our compression capacity;

• our lack of industry diversification; and

• legislative or regulatory changes, including changes in environmental regulations, environmental risks, regulations by the Federal Energy Regulatory Commission and liability under federal and state environmental laws and regulations.

Other factors that could cause our actual results to differ from our projected results are described under the caption “Risk Factors” and elsewhere in this offering memorandum and in our reports filed from time to time with the SEC and incorporated by reference in this offering memorandum.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

We are dependent on Chesapeake, Total and other producers for substantially all of our supply of natural gas volumes and are consequently subject to the risk of nonpayment or late payment by Chesapeake, Total or other producers of gathering, treating and compression fees. Chesapeake’s debt ratings for its senior notes are below investment grade, and they may remain below investment grade for the foreseeable future. Additionally, we are also subject to the risk that one or more of these customers default on its obligations under its gas gathering agreements with us. Not all of our counterparties under our gas gathering agreements are rated by credit rating agencies. Accordingly, this risk may be more difficult to evaluate than it would be with an investment grade or otherwise rated contract counterparty or with a more diversified group of customers, and unless and until we significantly increase our customer base, we expect to continue to be subject to significant and non-diversified risk of nonpayment or late payment of our fees.

Interest Rate Risk

Interest rates have recently experienced near record lows. If interest rates rise, our financing costs would increase accordingly. Although this could limit our ability to raise funds in the capital markets, we expect in this regard to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances. For the year ended December 31, 2011, a 125 basis point increase in the interest rate would have resulted in an $8.9 million decrease in net income.

Commodity Price Risk

We attempt to mitigate commodity price risk by contracting our operations on a long-term fixed-fee basis and through various provisions in our gas gathering agreements that are intended to support the stability of our cash flows. Natural gas prices are historically impacted by changes in the supply and demand of natural gas, as well as market uncertainty. However, an actual or anticipated prolonged reduction in natural gas prices or disparity in oil and natural gas pricing could result in reduced drilling in our areas of operations and, accordingly, in volumes of natural gas gathered by our systems. Notwithstanding the minimum volume commitments of Chesapeake and Total in our Barnett Shale region and the fee redetermination provisions under our gas gathering agreements, a reduction in volumes of natural gas gathered by our systems could adversely affect both our profitability and our cash flows. Adverse effects on our cash flows from reductions in natural gas prices could adversely affect our ability to make cash distributions to our unitholders.

We have agreed with our producer customers on caps on fuel and lost and unaccounted for gas on certain of our gathering systems in our operating regions. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel and lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

Additionally, an increase in commodity prices could result in increased costs of steel and other products that we use in the operation of our business, as well as the cost of obtaining rights-of-way for property on which our assets are located. Accordingly, our operating expenses and capital expenditures could increase as a result of an increase in commodity prices.

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ITEM 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

	Page
Management’s Report on Internal Control Over Financial Reporting		76
Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm		77
Consolidated Balance Sheets at December 31, 2011 and 2010		79
Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009		80
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		81
Consolidated Statements of Changes in Partners’ Capital for the Years Ended December  31, 2011, 2010 and 2009		82
Notes to Consolidated Financial Statements		83

75

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

It is the responsibility of the management of Chesapeake Midstream Partners, L.P. to establish and maintain adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management has assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2011, utilizing the Committee of Sponsoring Organizations of the Treadway Commission’s Internal Control—Integrated Framework (COSO framework).

Based on this evaluation, management has determined the Partnership’s internal control over financial reporting was effective as of December 31, 2011.

The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.

/s/ J. MIKE STICE

J. Mike Stice

Chief Executive Officer

/s/ DAVID C. SHIELS

David C. Shiels

Chief Financial Officer

76

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Chesapeake Midstream GP, L.L.C., as General Partner of Chesapeake Midstream Partners, L.P. and the Unitholders:

In our opinion, the accompanying consolidated balance sheets as of December 31, 2011 and 2010 and the related consolidated statements of operations, of changes in partners’ capital and of cash flows for the years then ended and the period from October 1, 2009 through December 31, 2009 present fairly, in all material respects, the financial position of Chesapeake Midstream Partners, L.P. and its subsidiaries (the “Partnership”) at December 31, 2011 and 2010, and the results of their operations and their cash flows for the years then ended and for the period from October 1, 2009 through December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Partnership’s internal control over financial reporting based on our audits (which was an integrated audit in 2011). 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financials statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Notes 5 and 7 to the accompanying consolidated financial statements, Chesapeake Midstream Partners, L.P. earned substantially all of its revenues and has other significant transactions with affiliated entities.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 29, 2012

77

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Chesapeake Midstream Development, L.P.:

In our opinion, the accompanying consolidated statements of operations, of changes in equity and of cash flows for the period January 1, 2009 through September 30, 2009 present fairly, in all material respects, the results of operations and cash flows of Chesapeake Midstream Development, L.P. and its subsidiaries (“predecessor Company”) for the period from January 1, 2009 through September 30, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As discussed in Notes 5 and 7 to the consolidated financial statements, Chesapeake Midstream Development L.P. earned substantially all of its revenues and has other significant transactions with affiliated entities.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

April 6, 2010

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CHESAPEAKE MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

	December 31, 2011			December 31, 2010
	($ in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	22		$	17,816
Accounts receivable, including $61,030 and $88,009 from related parties at December 31, 2011 and 2010, respectively		81,297			107,095
Other current assets		6,869			6,576
Total current assets		88,188			131,487
Property, plant and equipment:
Gathering systems		2,954,868			2,544,053
Other fixed assets		53,611			41,125
Less: Accumulated depreciation		(480,555	)		(358,269	)
Total property, plant and equipment, net		2,527,924			2,226,909
Investment in unconsolidated affiliates		886,558			—
Intangible customer relationships, net		158,621			172,481
Deferred loan costs, net		21,947			15,039
Total assets	$	3,683,238		$	2,545,916
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	57,546		$	39,619
Accrued liabilities, including $62,823 and $42,674 to related parties at December 31, 2011 and 2010, respectively		85,548			58,372
Total current liabilities		143,094			97,991
Long-term liabilities:
Long-term debt		1,062,900			249,100
Other liabilities		4,099			4,257
Total long-term liabilities		1,066,999			253,357
Commitments and contingencies (Note 13)
Partners’ capital:
Common units (78,876,643 and 69,083,265 issued and outstanding at December 31, 2011 and 2010, respectively)		1,561,504			1,285,619
Subordinated units (69,076,122 issued and outstanding at December 31, 2011 and 2010)		869,241			873,304
General partner interest		42,400			35,645
Total partners’ capital		2,473,145			2,194,568
Total liabilities and partners’ capital	$	3,683,238		$	2,545,916

The accompanying notes are an integral part of the consolidated financial statements.

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CHESAPEAKE MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

										Predecessor
	Year Ended December 31, 2011			Year Ended December 31, 2010			Three Months Ended December 31, 2009			Nine Months Ended September 30, 2009
	($ in thousands, except per unit data)
Revenues, including revenue from affiliates (Notes 5 and 7)	$	565,929		$	459,153		$	107,377		$	358,921
Operating expenses
Operating expenses, including expenses from affiliates (Note 5)		176,851			133,293			31,874			146,604
Depreciation and amortization expense		136,169			88,601			20,699			65,477
General and administrative expense, including expenses from affiliates (Note 5)		40,380			31,992			2,854			22,782
Impairment of property, plant and equipment and other assets		—			—			—			90,207
Loss on sale of assets		739			285			34			44,566
Total operating expenses		354,139			254,171			55,461			369,636
Operating income (loss)		211,790			204,982			51,916			(10,715	)
Other income (expense)
Income from unconsolidated affiliates		433			—			—			—
Interest expense (Note 12)		(14,884	)		(7,426	)		(619	)		(347	)
Other income		287			102			34			29
Income (loss) before income tax expense		197,626			197,658			51,331			(11,033	)
Income tax expense		3,289			2,431			639			6,341
Net income (loss)	$	194,337		$	195,227		$	50,692		$	(17,374	)
Limited partner interest in net income
Net income(1)	$	194,337		$	109,396			n/a			n/a
Less general partner interest in net income		(5,070	)		(2,188	)		n/a			n/a
Limited partner interest in net income		$ 189,267			$ 107,208			n/a			n/a
Net income per limited partner unit – basic and diluted
Common units	$	1.37		$	0.78			n/a			n/a
Subordinated units	$	1.37		$	0.78			n/a			n/a

⁽¹⁾  Reflective of general and limited partner interest in net income since closing the Partnership’s IPO on August 3, 2010. See Note 4 to the consolidated financial statements.

The accompanying notes are an integral part of the consolidated financial statements.

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CHESAPEAKE MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

										Predecessor
	Year Ended December 31, 2011			Year Ended December 31, 2010			Three Months Ended December 31, 2009			Nine Months Ended September 30, 2009
	($ in thousands)
Cash flows from operating activities:
Net income (loss)	$	194,337		$	195,227		$	50,692		$	(17,374	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		136,169			88,601			20,699			65,477
Deferred income taxes		—			—			—			6,341
Impairment of property, plant and equipment and other assets		—			—			—			90,207
Income from unconsolidated affiliates		(433	)		—			—			—
Loss on sale of assets		739			285			34			44,566
Other non-cash items		5,747			4,976			(39	)		(282	)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable		31,501			58,172			(70,792	)		(29,553	)
Increase (decrease) in other assets		(292	)		(4,833	)		(136	)		(1,901	)
Increase (decrease) in accounts payable		11,258			7,474			(23,630	)		(82,112	)
Increase (decrease) in accrued liabilities		19,990			(32,811	)		37,902			25,379
Net cash provided by operating activities		399,016			317,091			14,730			100,748
Cash flows from investing activities:
Additions to property, plant and equipment		(418,834	)		(216,303	)		(46,377	)		(756,883	)
Acquisition of gathering system assets		—			(500,000	)		—			—
Investment in unconsolidated affiliates		(600,000	)		—			—			—
Proceeds from sale of assets		1,730			4,823			25			65,889
Net cash used in investing activities		(1,017,104	)		(711,480	)		(46,352	)		(690,994	)
Cash flows from financing activities:
Proceeds from long-term debt borrowings		1,576,700			529,300			100,744			870,373
Payments on long-term debt borrowings		(1,112,900	)		(324,300	)		(68,817	)		(1,318,200	)
Proceeds from issuance of common units, net of offering costs		—			474,579			—			—
Proceeds from issuance of senior notes		350,000			(30,522	)		—			—
Distributions to unit holders		(200,897	)		—			—			—
Distributions to partners		—			(231,919	)		—			(10,153	)
Contribution from predecessor		—			177			—			—
Contributions from Chesapeake		—			—			—			567,828
Proceeds from sale of noncontrolling interest		—			—			—			587,500
Joint venture transaction costs		—			—			—			(16,130	)
Debt issuance cost		(11,332	)		(5,113	)		(337	)		(16,950	)
Initial public offering costs		(1,280	)		—			—			—
Other adjustments		3			—			—			—
Net cash provided by financing activities		600,294			412,202			31,590			664,268
Net increase (decrease) in cash and cash equivalents		(17,794	)		17,813			(32	)		74,022
Cash and cash equivalents, beginning of period		17,816			3			35			82,025
Cash and cash equivalents, end of period	$	22		$	17,816			3			156,047
Supplemental disclosure of non-cash investing activities:
Changes in accounts payable and other liabilities related to purchases of property, plant and equipment	$	8,589		$	12,633		$	(2,812	)	$	(52,521	)
Changes in other liabilities related to asset retirement obligations	$	324		$	28		$	136		$	(2,893	)
Contributions of property, plant and equipment to Chesapeake	$	—		$	11,705		$	1,749		$	91,462
Supplemental disclosure of non-cash financing activities:
Issuance of 9,791,605 units to Chesapeake for acquisition of Appalachia Midstream	$	279,257		$	—		$	—		$	—
Issuance of general partner interests	$	5,702		$	—		$	—		$	—
Supplemental disclosure of cash payments for interest	$	16,957		$	3,607		$	877		$	7,478
Supplemental disclosure of cash payments for taxes	$	2,830		$	645		$	—		$	—

The accompanying notes are an integral part of the consolidated financial statements.

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CHESAPEAKE MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

				Partners’ Equity
				Limited Partners
	Members’ Equity			Common			Subordinated			General Partner			Total
	($ in thousands)
Predecessor:
Balance at December 31, 2008	$	1,793,269		$	—		$	—		$	—		$	1,793,269
Contributions from Chesapeake		659,291			—			—			—			659,291
Net loss		(17,374	)		—			—			—			(17,374	)
Sale of noncontrolling interest in midstream joint venture		587,500			—			—			—			587,500
Noncontrolling interest offering cost		(16,130	)		—			—			—			(16,130	)
Distribution to noncontrolling interest owner		(10,153	)		—			—			—			(10,153	)
Balance at September 30, 2009	$	2,996,403		$	—		$	—		$	—		$	2,996,403
Successor:
Members’ equity upon formation		1,741,186			—			—			—			1,741,186
Contributions from predecessor		1,749			—			—			—			1,749
Net income		50,692			—			—			—			50,692
Balance at December 31, 2009	$	1,793,627		$	—		$	—		$	—		$	1,793,627
Distributions to predecessor, net		(6,574	)		—			—			—			(6,574	)
Distributions to members		(169,500	)		—			—			—			(169,500	)
Net income attributable to the period from January 1, 2010 through August 2, 2010		85,831			—			—			—			85,831
Contribution of net assets to Chesapeake Midstream Partners, L.P.		(1,703,384	)		834,658			834,658			34,068			—
Issuance of common units to public, net of offering and other costs		—			474,579			—			—			474,579
Distribution of proceeds to partner from exercise of over-allotment option		—			(62,419	)		—			—			(62,419	)
Non-cash equity based compensation		—			150			—			—			150
Distributions to unitholders		—			(14,956	)		(14,955	)		(611	)		(30,522	)
Net income attributable to the period from August 3, 2010 through December 31, 2010		—			53,607			53,601			2,188			109,396
Balance at December 31, 2010	$	—		$	1,285,619		$	873,304		$	35,645		$	2,194,568
Net income		—			94,896			94,371			5,070			194,337
Distribution to unitholders		—			(98,446	)		(98,434	)		(4,017	)		(200,897	)
Initial public offering costs		—			(1,280	)		—			—			(1,280	)
Non-cash equity based compensation		—			1,458			—			—			1,458
Issuance of common units		—			279,257			—			—			279,257
Issuance of general partner interests		—			—			—			5,702			5,702
Balance at December 31, 2011	$	—		$	1,561,504		$	869,241		$	42,400		$	2,473,145

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CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Description of Business and Basis of Presentation

Basis of presentation.  Chesapeake Midstream Partners, L.P., (the “Partnership”) a Delaware limited partnership formed in January 2010, is principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. As of December 31, 2011, the Partnership’s assets consisted of 187 gathering systems, 5 natural gas treating facilities, 3 gas processing facilities and an ownership interest in 10 additional gas gathering systems. The Partnership’s assets are located in Texas, Louisiana, Oklahoma, Kansas, Arkansas, West Virginia and Pennsylvania. The Partnership provides gathering, treating and compression services to Chesapeake Energy Corporation and Total Gas and Power North America, Inc., the Partnership’s primary customers, and other producers under long-term, fixed-fee contracts.

For purposes of these financial statements, the “Partnership,” when used in a historical context, refers to the financial results of Chesapeake Midstream Partners, L.L.C. from its inception on September 30, 2009 through the closing date of its initial public offering (“IPO”) on August 3, 2010 and to Chesapeake Midstream Partners, L.P. and its subsidiaries thereafter. “CMD” or the “predecessor” refers to Chesapeake Midstream Development, L.P. prior to September 30, 2009. “Chesapeake” refers to Chesapeake Energy Corporation and “GIP” refers to Global Infrastructure Partners – A, L.P., and affiliated funds managed by Global Infrastructure Management, LLC, and certain of their respective subsidiaries and affiliates. “Total”, when discussing the upstream joint venture with Chesapeake, refers to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A., and when discussing the Partnership’s gas gathering agreement and related matters, refers to Total E&P USA, Inc. and Total Gas & Power North America, Inc., a wholly owned subsidiary of Total S.A.

CMD is a Delaware limited partnership formed on February 29, 2008 to own, operate and develop midstream energy assets. Upon formation, gathering and treating assets of Chesapeake Energy Marketing, Inc. (“CEMI”), a wholly owned subsidiary of Chesapeake, were contributed to CMD. CEMI is the sole limited partner of CMD with a 98 percent ownership interest, and Chesapeake Midstream Management L.L.C. (“CMM”) is the general partner of CMD with a 2 percent ownership interest. CMM is a wholly owned subsidiary of CEMI.

On September 30, 2009, the predecessor formed a joint venture with Global Infrastructure Partners – A, L.P., and affiliated funds managed by Global Infrastructure Management, LLC, and certain of their respective subsidiaries and affiliates, to own and operate natural gas midstream assets. As part of the transaction, the predecessor contributed certain natural gas gathering and treating assets to a new entity, Chesapeake Midstream Partners, L.L.C. and GIP purchased a 50 percent interest in the newly formed joint venture.

The assets contributed to the joint venture and ultimately the Partnership were substantially all of its predecessor’s midstream assets in the Barnett Shale region and certain of its midstream assets in the Anadarko, Arkoma, Delaware and Permian Basins. Subsidiaries of the predecessor continued to operate midstream assets outside of the joint venture. At December 31, 2011, these included natural gas gathering assets primarily in the Haynesville Shale, Marcellus Shale (including other areas in the Appalachian Basin), Utica Shale and the Eagle Ford Shale.

The accompanying consolidated financial statements are presented for current and predecessor periods, which relate to the accounting periods preceding and succeeding the September 30, 2009 joint venture transaction described in Note 1. The current and predecessor periods have been

83

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

separated by a vertical line on the face of the consolidated financial statements to highlight the fact that the financial information for such periods represents different entities.

The accompanying consolidated financial statements of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). To conform to these accounting principles, management makes estimates and assumptions that affect the amounts reported in the consolidated financial statements and the notes thereto. These estimates are evaluated on an ongoing basis, utilizing historical experience and other methods considered reasonable under the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates. Effects on the Partnership’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.

Offerings and acquisitions.

IPO.  On August 3, 2010, the Partnership completed its IPO of 24,437,500 common units (including 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option on August 3, 2010) at a price of $21.00 per unit. The Partnership’s common units are listed on the New York Stock Exchange (the “NYSE”) under the symbol “CHKM”.

The Partnership received gross offering proceeds of approximately $513.2 million less approximately $38.6 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of the contribution agreement, the Partnership distributed the approximate $62.4 million of net proceeds from the exercise of the over-allotment option to GIP on August 3, 2010. Upon completion of the IPO, Chesapeake and GIP conveyed to the Partnership a 100 percent membership interest in Chesapeake MLP Operating, L.L.C., which owned all of its assets since September 2009.

Haynesville acquisition.  On December 21, 2010, the Partnership acquired the Springridge gathering system and related facilities from CMD for $500.0 million. The acquisition was financed with a draw on the Partnership’s revolving credit facility of approximately $234.0 million plus approximately $266.0 million of cash on hand. The Springridge gathering system is primarily located in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, the Partnership entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication, annual fee redetermination and a minimum volume commitment. These assets are referred to collectively as the “Springridge assets” and the acquisition is referred to as the “Springridge acquisition.”

Marcellus acquisition.  On December 29, 2011, the Partnership acquired from CMD, all of the issued and outstanding common units of Appalachia Midstream Services, L.L.C. (“Appalachia Midstream”) for total consideration, which is subject to a customary post-closing working capital adjustment, of $879.3 million, consisting of 9,791,605 common units and $600.0 million in cash that was financed with a draw on the Partnership’s revolving credit facility. Through the acquisition of Appalachia Midstream, the Partnership operates 100 percent of and owns an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 231 miles of gas gathering pipeline in the Marcellus Shale. The remaining 53 percent interest in these assets is owned primarily by Statoil ASA (“Statoil”), Anadarko Petroleum Corporation (“Anadarko”), Epsilon Energy Ltd. (“Epsilon”), Mitsui & Co., Ltd. (“Mitsui”). Gross throughput for these assets at December 31, 2011,

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was just over 1.0 Bcf per day (approximately 470 Mmcf per day net to the Partnership). Appalachia Midstream operates the assets under 15-year fixed fee gathering agreements. The gathering agreements include significant acreage dedications and annual fee redeterminations. In addition, CMD has committed to pay the Partnership quarterly any shortfall between the actual EBITDA from these assets and specified quarterly targets, with the quarterly targets adding to a total of $100 million in 2012 and $150 million in 2013.

Limited partner and general partner units.  The following table summarizes common, subordinated and general partner units issued during the years ended December 31, 2011 and 2010:

	Limited Partner Units				General Partner Interests		Total
	Common		Subordinated
Balance at December 31, 2009		—		—		—		—
Initial public offering and contribution of initial assets		69,076,122		69,076,122		2,819,434		140,971,678
Long-term incentive plan awards		7,143		—		—		7,143
Balance at December 31, 2010		69,083,265		69,076,122		2,819,434		140,978,821
Long-term incentive plan awards		1,773		—		172		1,945
December 2011 equity issuance		9,791,605		—		199,838		9,991,443
Balance at December 31, 2011		78,876,643		69,076,122		3,019,444		150,972,209

Holdings of partnership equity.  At December 31, 2011, Chesapeake held 1,509,722 general partner units representing a 1.0 percent general partner interest in the Partnership, 50 percent of the Partnership IDRs, 33,704,666 common units and 34,538,061 subordinated units. Chesapeake’s common and subordinated units represent an aggregate 45.2 percent limited partner interest in the Partnership. The Partnership issued 9,791,605 shares to Chesapeake in connection with the Marcellus acquisition. GIP held 1,509,722 general partner units representing a 1.0 percent general partner interest in the Partnership, 50 percent of the Partnership IDRs, 10,497,003 common units and 34,538,061 subordinated units. GIP’s common and subordinated units represent an aggregate 29.8 percent limited partner interest in the Partnership. The public held 34,674,974 common units, representing a 23.0 percent limited partner interest in the Partnership. In February 2012, GIP completed a public offering of their remaining 10,497,003 common units.

2. Summary of Significant Accounting Policies

Use of estimates.  The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. Significant estimates include: (1) estimated useful lives of assets, which impacts depreciation and amortization; (2) accruals related to revenues, expenses and capital costs; (3) liability and contingency accruals; and (4) cost allocations as described in Note 5. Although management believes these estimates are reasonable, actual results could differ from the Partnership’s estimates.

Cash and cash equivalents.  For purposes of the consolidated financial statements, investments in all highly liquid instruments with original maturities of three months or less at date of purchase are

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considered to be cash equivalents. The Partnership had approximately $22 thousand and $17.8 million of cash and cash equivalents as of December 31, 2011 and 2010, respectively. Book overdrafts are checks that have been issued before the end of the period, but not presented to the bank for payment before the end of the period. At December 31, 2011 and 2010, book overdrafts of $8.5 million and $4.0 million, respectively, were included in accounts payable.

Accounts receivable.  The majority of accounts receivable relate to gathering and treating activities. Accounts receivable included in the balance sheets are reflected net of an allowance for doubtful accounts, if warranted. At December 31, 2011, the Partnership had an allowance for doubtful accounts of $0.4 million. No allowance for doubtful accounts was necessary at December 31, 2010.

Property, plant and equipment.  Property, plant and equipment are recorded at cost. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. As assets are disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in operating expenses in the statements of operations. The predecessor recorded a $44.6 million loss on the sale of certain non-core, non-strategic gathering systems during the period ended September 30, 2009.

Certain of the gathering systems of the Partnership are subject to an agreement with a subsidiary of Chesapeake, which provides the Partnership rights and obligations equivalent to a capital lease. Under the terms of the agreement, the Partnership has rights to the associated capital assets for as long as the assets are in operation. Specifically, the Partnership will pay all costs associated with the related gathering systems, including all capital costs, operating costs and direct and indirect overhead costs. In exchange for paying such costs and for the services it provides pursuant to this agreement, the Partnership receives revenues derived from operation of the gathering systems. At December 31, 2011 and 2010, approximately $124.5 million and $122.5 million ($105.0 million and $109.2 million net of accumulated depreciation) of the Partnership’s gathering system assets were held under such agreement, respectively. Payments for capital costs under the agreement are made as the associated capital assets are constructed and, accordingly, the Partnership has no capital lease obligation liability associated with the assets held under this agreement as of December 31, 2011.

Depreciation is calculated using the straight-line method, based on the assets’ estimated useful lives. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets.

Impairment of long-lived assets.  Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount that the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risks associated with achieving the underlying cash flows.

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During 2009, the predecessor recognized an impairment charge of $86.2 million associated with certain mid-continent gathering systems. The impairment was the result of a reduction in the future expected throughput volumes on these systems by Chesapeake based on its revised future development plans of the underlying oil and gas properties, as well as the impact of the terms of the new gas gathering agreements entered into with Chesapeake in conjunction with the formation of the joint venture on September 30, 2009. These systems were subsequently contributed to the Partnership upon its formation. Additionally, the predecessor also expensed $4 million of debt issuance costs as a result of the amendment of the credit facility (See Note 12) resulting in total impairments of $90.2 million in 2009.

Equity Method Investments.  The equity method of accounting is used to account for the Partnership’s interest in Appalachia Midstream, which was acquired on December 29, 2011. Through the acquisition of Appalachia Midstream, the Partnership operates 100 percent of and owns an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 231 miles of gas gathering pipeline in the Marcellus Shale. The remaining 53 percent interest in these assets is owned primarily by Statoil, Anadarko, Epsilon and Mitsui. See Note 1 – Description of Business and Basis of Presentation for more information on the acquisition.

Asset retirement obligations.  Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at the Partnership’s fair value measured using expected discounted future cash outflows of the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Accretion expense is recognized over time as the discounted liability is accreted to the Partnership’s expected settlement value. Subsequent to the initial recognition, the liability is adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) and for accretion of the liability due to the passage of time, until the obligation is settled. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the associated asset carrying amount. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, retirement costs and the estimated timing of settling asset retirement obligations.

Fair value.  The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

Level 1—inputs represent quoted prices in active markets for identical assets or liabilities.

Level 2—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3—inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement).

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Nonfinancial assets and liabilities initially measured at fair value include third-party business combinations, impaired long-lived assets (asset groups), and initial recognition of asset retirement obligations.

The fair value of debt is the estimated amount the Partnership would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices or average valuations of similar debt instruments at the balance sheet date for those debt instruments for which quoted market prices are not available. See Note 12—Debt and Interest Expense for disclosures regarding the fair value of debt.

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the balance sheet approximates fair value.

Segments.  The Partnership’s operations are organized into a single business segment, the assets of which consist of natural gas gathering systems, treating facilities, processing facilities, pipelines and related plant and equipment.

Revenue recognition.  The predecessor’s revenues were derived almost exclusively from related parties and were charged under short-term contracts at market sensitive rates. In 2011, the Partnership derived substantially all of its revenues through gas gathering agreements with Chesapeake and Total. Pursuant to the applicable gas gathering agreements, Chesapeake and Total have agreed to minimum volume commitments covering production in the Barnett Shale region for each year through December 31, 2018 and for the six month period ending June 30, 2019, and, solely with respect to Chesapeake, in the Haynesville Shale region for each year through December 31, 2013. In the event either Chesapeake or Total does not meet its minimum volume commitment to the Partnership in the Barnett Shale region or Chesapeake does not meet its minimum volume commitment to the Partnership in the Haynesville Shale region, for any annual period (or six month period with respect to the six months ending June 30, 2019 in the Barnett Shale region) during the minimum volume commitment period, Chesapeake and Total will be obligated to pay a fee equal to the applicable fee for each Mcf by which the applicable party’s minimum volume commitment for such year (or six month period with respect to the six months ending June 30, 2019) exceeds the actual volumes gathered from such party’s production. The revenue associated with such shortfall fees is recognized in the fourth quarter of each year.

Revenues consist of fees recognized for the gathering, treating and compression of natural gas to major interstate and intrastate pipelines. Revenues are recognized when the service is performed and is based upon non-regulated rates and the related gathering, treating and compression volumes.

Deferred Loan Costs.  External costs incurred in connection with closing the revolving bank credit facilities are capitalized as deferred loan costs and amortized over the life of the related agreement. Amortization is included in interest expense in the statement of operations.

Environmental expenditures.  Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. There are no liabilities reflected in the accompanying financial statements at December 31, 2011 and 2010.

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Equity Based Compensation.  Certain employees of Chesapeake have been seconded to the Partnership to provide operating, routine maintenance and other services with respect to the business under the direction, supervision and control of the Partnership’s general partner. A number of these employees receive equity-based compensation through Chesapeake’s stock-based compensation programs, which consist of restricted stock issued to employees.

The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. However, the Partnership’s expense is allocated based on the lesser of the value at grant date or vest date. This value is amortized over the vesting period, which is generally four or five years from the date of grant. To the extent compensation cost relates to employee activities directly involved in gathering or treating operations, such amounts are charged to the Partnership and its predecessor and are reflected as operating expenses. Included in operating expenses is stock-based compensation of $3.8 million, $2.1 million and $0.6 million for the Partnership during the years ended December 31, 2011 and 2010, and three months ended December 31, 2009, respectively, and $5.3 million for its predecessor during the period ended September 30, 2009. To the extent compensation cost relates to employees indirectly involved in gathering or treating operations, such amounts are charged to the Partnership and its predecessor through an overhead allocation and are reflected as general and administrative expenses.

The Chesapeake Midstream Long-Term Incentive Plan (“LTIP”) provides for an aggregate of 3,500,000 common units to be awarded to employees, directors and consultants of the Partnership’s general partner and its affiliates through various award types, including unit awards, restricted units, phantom units, unit options, unit appreciation rights and other unit-based awards. The LTIP has been designed to promote the interests of the Partnership and its unitholders by strengthening its ability to attract, retain and motivate qualified individuals to serve as employees, directors and consultants.

The following table summarizes LTIP award activity for the year ended December 31, 2011:

	Units			Value per Unit
Restricted units unvested at beginning of period		—		$	—
Granted		288,417			28.50
Vested		(1,773	)		28.78
Forfeited		(13,386	)		28.51
Restricted units unvested at end of period		273,258		$	28.50

Intangible Assets.   Intangible assets are generally amortized on a straight-line basis over their estimated useful lives, unless the assets economic benefits are consumed on an other than straight-line basis. The estimated useful life is the period over which the assets are expected to contribute directly or indirectly to the Partnership’s future cash flows. The estimated useful life of the customer relationship acquired with the Springridge gathering system is 15 years.

The Partnership assesses long-lived assets, including property, plant and equipment and intangible assets, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed by comparing the carrying amount of an asset to undiscounted future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured as the amount by which the carrying amounts exceed the fair value of the assets.

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Business Combinations.   The Partnership makes various assumptions in developing models for determining the fair values of assets and liabilities associated with business acquisitions. These fair value models, developed with the assistance of outside consultants, apply discounted cash flow approaches to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions to arrive at an economic value for the business acquired. The Partnership then determines the fair value of the tangible assets based on estimates of replacement costs less obsolescence. Identifiable intangible assets acquired consist primarily of customer contracts, customer relationships, trade names, and licenses and permits. The Partnership values customer relationships using a discounted cash flow model.

Income taxes.   Chesapeake and its subsidiaries historically have filed a consolidated federal income tax return and other state returns as required. The predecessor and certain of its subsidiaries, as a partnership or limited liability companies, were not subject to federal income taxes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to the partners of the predecessor and, accordingly, do not result in a provision for income taxes in the accompanying financial statements. As a master limited partnership, the Partnership is a pass-through entity and also not subject to federal income taxes and most state income taxes with the exception of Texas Franchise Tax. For federal and state income tax purposes, all income, expenses, gains, losses and tax credits generate flow through to the owners, and accordingly, do not result in a provision for income taxes.

Income taxes have been provided by the predecessor for its subsidiaries which are subject to federal and state income tax on the basis of their separate company income and deductions. Income taxes have also been provided for the operations of the midstream business prior to its contribution to the predecessor on February 28, 2008, during which period the operations were owned by CEMI and were subject to income taxes. Deferred income taxes have been provided for temporary differences between the book and tax carrying amounts of assets and liabilities held by taxable entities of the predecessor. These differences create taxable or tax deductible amounts for future periods. Current taxes payable of the Partnership related to Texas franchise tax will be paid by the Partnership. Current taxes payable of the predecessor were paid by Chesapeake and have been reflected as contributions from Chesapeake in the accompanying statements of partners’ capital/division equity. Chesapeake reimbursed the predecessor for its net operating losses utilized in the completion of Chesapeake’s consolidated federal tax returns.

There were no uncertain tax positions at December 31, 2009.

3. Partnership Distributions

The partnership agreement requires that, within 45 days subsequent to the end of each quarter, beginning with the quarter ended September 30, 2010, the Partnership distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. During the years ended December 31, 2011 and 2010, the Partnership paid cash distributions to its unitholders of approximately $200.9 million and $30.5 million, respectively, representing the four distributions in 2011 and only one distribution in 2010. See also Note 15—Subsequent Events concerning distributions approved in January 2012 for the quarter ended December 31, 2011.

Available cash.   The amount of available cash (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter less the amount of cash reserves established by the Partnership’s general partner to provide for the proper conduct of its business, including reserves to fund future capital expenditures, to comply with applicable laws, or its debt instruments and other

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agreements, or to provide funds for distributions to its unitholders and to its general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement.

Minimum Quarterly Distribution.   The partnership agreement provides that, during the subordination period, the common units are entitled to distributions of available cash each quarter in an amount equal to the minimum quarterly distribution, which is $0.3375 per common unit for a full fiscal quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Furthermore, arrearages do not apply to and therefore will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the subordination period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to or greater than the minimum quarterly distribution.

The subordination period will lapse at such time when the Partnership has earned and paid at least the quarterly minimum distribution per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2013. Also, if the Partnership has earned and paid at least 150 percent of the minimum quarterly distribution on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of removal. When the subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages. All subordinated units are held indirectly by Chesapeake and GIP.

General Partner Interest and Incentive Distribution Rights.   The Partnership’s general partner is entitled to two percent of all quarterly distributions that the Partnership makes prior to its liquidation. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. The general partner’s initial two percent interest in the Partnership’s distributions may be reduced if the Partnership issues additional limited partner units in the future (other than the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and its general partner does not contribute a proportionate amount of capital to the Partnership to maintain its two percent general partner interest. After distributing amounts equal to the minimum quarterly distribution to common and subordinated unitholders and distributing amounts to eliminate any arrearages to common unitholders, the Partnership’s general partner is entitled to incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds specified target levels shown below:

	Total quarterly distribution per unit		Unitholders			General partner
Minimum Quarterly Distribution		$0.3375		98.0	%		2.0	%
First Target Distribution		up to $0.388125		98.0	%		2.0	%
Second Target Distribution		above $0.388125 up to $0.421875		85.0	%		15.0	%
Third Target Distribution		above $0.421875 up to $0.50625		75.0	%		25.0	%
Thereafter		above $0.50625		50.0	%		50.0	%

The table above assumes that the Partnership’s general partner maintains its 2 percent general partner interest, that there are no arrearages on common units and the general partner continues to

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own the IDRs. The maximum distribution sharing percentage of 50.0 percent includes distributions paid to the general partner on its two percent general partner interest and does not include any distributions that the general partner may receive on limited partner units that it owns or may acquire.

4. Net Income per Limited Partner Unit

The Partnership’s net income attributable to the Partnership Assets for periods including and subsequent to the Partnership’s acquisitions of the Partnership Assets is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to unvested units granted under the LTIP and incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to available cash (as defined by the partnership agreement) for the period. The Partnership’s net income allocable to the limited partners is allocated between the common and subordinated unitholders by applying the provisions of the partnership agreement that govern actual cash distributions as if all earnings for the period had been distributed. Accordingly, if current net income allocable to the limited partners is less than the minimum quarterly distribution, or if cumulative net income allocable to the limited partners since August 3, 2010 is less than the cumulative minimum quarterly distributions, more income is allocated to the common unitholders than the subordinated unitholders for that quarterly period.

Basic and diluted net income per limited partner unit is calculated by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period. The common units issued during the period are included on a weighted-average basis for the days in which they were outstanding.

The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated limited partner units (in thousands, except per-unit information):

	Years Ended
	December 31, 2011		December 31, 2010
Net income.	$	194,337	$	195,227
Less Successor interest in net income (1)		—		85,831
Less general partner interest in net income		5,070		2,188
Limited partner interest in net income	$	189,267	$	107,208
Net income allocable to common units	$	94,896	$	53,607
Net income allocable to subordinated units		94,371		53,601
Limited partner interest in net income	$	189,267	$	107,208
Net income per limited partner unit – basic and diluted
Common units	$	1.37	$	0.78
Subordinated units		1.37		0.78
Total limited partner units	$	1.37	$	0.78
Weighted average limited partner units outstanding – basic and diluted
Common units		69,371,194		69,083,265
Subordinated units		69,076,122		69,076,122
Total		138,447,316		138,159,387

⁽¹⁾  Includes net income attributable to the initial assets up to August 3, 2010.

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5. Transactions with Affiliates

Affiliate transactions.  In the normal course of business, natural gas gathering and treating services are provided to Chesapeake and its affiliates. Revenues are derived almost exclusively from Chesapeake, which includes volumes attributable to third-party interest owners that participate in Chesapeake’s operated wells.

Contribution of Partnership Assets to the Partnership.  Upon closing of the IPO in August 2010, Chesapeake and GIP conveyed to the Partnership a 100 percent membership interest in Chesapeake MLP Operating, L.L.C., which owned all of the Partnership’s assets since September 2009. See Note 1—Description of Business and Basis of Presentation.

Omnibus Agreement.  The Partnership has entered into an omnibus agreement with Chesapeake Midstream Ventures and Chesapeake Midstream Holdings that addresses the following matters:

• Chesapeake’s obligation to provide the Partnership with certain rights relating to certain future midstream business opportunities; and

• the Partnership’s right to indemnification for certain liabilities and its obligation to indemnify Chesapeake Midstream Ventures and affiliated parties for certain liabilities.

General and Administrative Services and Reimbursement.  Pursuant to a services agreement, Chesapeake and its affiliates provide certain services including legal, accounting, treasury, human resources, information technology and administration. The employees supporting these operations are employees of CEMI or Chesapeake. The consolidated financial statements for the Partnership and the predecessor include costs allocated from Chesapeake and CEMI for centralized general and administrative services, as well as depreciation of assets utilized by Chesapeake’s centralized general and administrative functions. Effective October 1, 2009, the Partnership was charged a general and administrative fee from Chesapeake based on the terms of the joint venture agreement. The established terms indicate corporate overhead costs are charged to the Partnership based on actual cost of the services provided, subject to a fee per Mcf cap based on volumes of natural gas gathered. The fee is calculated as the lesser of $0.03065/Mcf gathered or actual corporate overhead costs. General and administrative charges were $23.7 million, $17.0 million and $2.2 million for the years ended December 31, 2011 and 2010, and three months ended December 31, 2009, for the Partnership. General and administrative charges were $14.6 million for the nine months ended September 30, 2009 for the predecessor.

Additional Services and Reimbursement.  At the Partnership’s request, Chesapeake also provides the Partnership with certain additional services under the services agreement, including engineering, construction, procurement, business analysis, commercial, cartographic and other similar services to the extent they are not already provided by the seconded employees. In return for such additional services, the general partner reimburses Chesapeake on a monthly basis an amount equal to the time and materials actually spent in performing the additional services. The reimbursement for additional services is not subject to the general and administrative services reimbursement cap.

Chesapeake has agreed to perform all services under the relevant provisions of the services agreement using at least the same level of care, quality, timeliness and skill as it does for itself and its affiliates and with no less than the same degree of care, quality, timeliness and skill as its past practice in performing the services for itself and the Partnership’s business during the one year period prior to September 30, 2009. In any event, Chesapeake has agreed to perform such services using no less than a reasonable level of care in accordance with industry standards.

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In connection with the services arrangement, the Partnership reimburses GIP for certain costs incurred by GIP in connection with assisting the Partnership in the operation of its business. For the years ended December 31, 2011 and 2010, the cost was $0.6 million and $0.9 million, respectively, for these support services.

The term of the services agreement will extend for additional twelve-month periods unless any party provides 180 days’ prior written notice otherwise prior to the expiration of the applicable twelve-month period ending on December 31.

Employee Secondment Agreement.  Chesapeake, certain of its affiliates and the Partnership’s general partner have entered into an amended and restated employee secondment agreement pursuant to which specified employees of Chesapeake are seconded to the general partner to provide operating, routine maintenance and other services with respect to the Partnership’s business under the direction, supervision and control of the general partner. Additionally, all of the Partnership’s executive officers other than its chief executive officer, Mr. Stice, are seconded to the general partner pursuant to this agreement. The general partner, subject to specified exceptions and limitations, reimburses Chesapeake on a monthly basis for substantially all costs and expenses Chesapeake incurs relating to such seconded employees, including the cost of their salaries, bonuses and employee benefits, including 401(k), restricted stock grants and health insurance and certain severance benefits. Charges to the Partnership for the services rendered by such seconded employees were $42.1 million and $30.3 million for the years ended December 31, 2011 and 2010, respectively. These charges include $37.7 million and $28.3 million in operating expenses and $4.4 million and $2.0 million in general and administrative expenses for the years end December 31, 2011 and 2010, respectively, in the accompanying consolidated statements of operations.

The initial term of the employee secondment agreement extends through September 30, 2014. The term will automatically extend for additional twelve month periods unless any party provides 90 days’ prior written notice otherwise prior to the expiration of the initial term or the applicable twelve month period. The Partnership’s general partner may terminate the agreement at any time upon 90 days’ prior written notice.

Shared Services Agreement.  In return for the services of Mr. Stice as the chief executive officer of the Partnership’s general partner, its general partner has entered into a shared services agreement with Chesapeake pursuant to which its general partner reimburses certain of the costs and expenses incurred by Chesapeake in connection with Mr. Stice’s employment. The general partner is generally expected, subject to certain exceptions, to reimburse Chesapeake for 50 percent of the costs and expenses of the amounts provided to Mr. Stice in his employment agreement; however, the ultimate reimbursement obligation is determined based on the amount of time Mr. Stice actually spends working for the Partnership. The reimbursement obligations of its general partner will continue for so long as Mr. Stice is employed by both the general partner and Chesapeake.

Gas Compressor Master Rental and Servicing Agreement.  The Partnership has entered into a gas compressor master rental and servicing agreement with MidCon Compression, L.L.C., (“MidCon Compression”) a wholly owned indirect subsidiary of Chesapeake, pursuant to which MidCon Compression agreed to lease to the Partnership certain compression equipment that the Partnership uses to compress gas gathered on its gathering systems outside the Marcellus Shale and provide certain related services. In return for the lease of such equipment, the Partnership pays specified monthly rates per specified compression units, subject to an annual escalator to be applied on

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October 1st of each year and a redetermination of such specified monthly rates to market rates effective no later than October 1, 2016. Under the compression agreement, the Partnership granted MidCon Compression the exclusive right to lease and rent compression equipment to the Partnership in the acreage dedications through September 30, 2016. Thereafter, the Partnership will have the right to continue leasing such equipment through September 30, 2019 at market rental rates to be agreed upon between the parties or to lease compression equipment from unaffiliated third parties. MidCon Compression guarantees to the Partnership that the leased compressors will meet specified run time and throughput performance guarantees. The monthly rental rates are reduced for any leased equipment that does not meet these guarantees. The Partnership leases substantially all of the compression capacity for its existing gathering systems in the Marcellus Shale from MidCon Compression under a long-term contract expiring on January 31, 2021 pursuant to which the Partnership has agreed to pay specified monthly rates under a fixed-fee structure subject to an annual escalator. This agreement is not subject to an exclusivity provision. Compressor rental charges from affiliates were $57.6 million, $47.8 million and $11.7 million for the years ended December 31, 2011 and 2010 and three months ended December 31, 2009, respectively. Compressor rental charges from affiliates were $47.3 million for the nine months ended September 30, 2009, for the predecessor. These charges are included in operating expenses in the accompanying consolidated statements of operations.

The Partnership is obligated to maintain general liability and property insurance, including machinery breakdown insurance with respect to the leased equipment. In addition, MidCon Compression has agreed to provide the Partnership with emission testing and other related services at monthly rates. The Partnership or MidCon Compression may terminate these services upon not less than six months notice.

The compression agreement expires on September 30, 2019 but will continue from year to year thereafter, unless terminated by the Partnership no less than 60 days prior to the end of the term or any year thereafter. Additionally, either party may terminate in specified circumstances, including upon the other party’s failure to perform material obligations under the compression agreement if such failure is not cured within 60 days after notice thereof.

In connection with the acquisition of the Springridge gathering system, the previously existing above-described gas compressor master rental and servicing agreement was amended and restated, on terms substantially similar to those under the Partnership’s original compression agreement, to include the AMI associated with the Springridge natural gas gathering system and to allow for the addition of future AMIs.

Inventory Purchase Agreement.  Upon completion of the IPO, the Partnership entered into an inventory purchase agreement pursuant to which the Partnership agreed beginning as of September 30, 2009 to purchase from Chesapeake, in each case on terms and conditions to be mutually agreed upon by Chesapeake and the Partnership, its first $60.0 million of requirements of pipes that are useful in the conduct of the natural gas gathering, compression, dehydrating, treating and transportation business at a specified price per ton. For the years ended December 31, 2011 and 2010, the Partnership purchased approximately $23.4 million and $36.6 million, respectively, of inventory pursuant to this inventory purchase agreement and incorporated in the Partnership’s property, plant and equipment, thus satisfying the terms of this agreement.

Gas Gathering Agreements.  The Partnership is party to (i) a 20-year gas gathering agreement with respect to the Barnett Shale and the Mid-Continent region with certain subsidiaries of Chesapeake that was entered into in connection with the creation of its predecessor in September 2009, (ii) a

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20-year gas gathering agreement with respect to the Barnett Shale with Total that was entered into in connection with an upstream joint venture transaction between Chesapeake and Total E&P in January 2010, (iii) a 10-year gas gathering agreement with certain subsidiaries of Chesapeake that was entered into concurrent with the closing of the Partnership’s acquisition of the Springridge gas gathering system in the Haynesville Shale in December 2010 and (iv) through Appalachia Midstream, 15-year gas gathering agreements with certain subsidiaries of Chesapeake, Statoil, Anadarko, Epsilon, Mitsui and Chief that the Partnership acquired in connection with the acquisition of Appalachia Midstream in December 2011.

Future revenues under the Partnership’s gas gathering agreements will be derived pursuant to terms that will differ between the Partnership’s operating regions.

If one of the counterparties to the gas gathering agreements sells, transfers or otherwise disposes to a third party properties within the Partnership’s acreage dedications, it will be required to cause the third party to either enter into the existing gas gathering agreement or enter into a new gas gathering agreement with the Partnership on substantially similar terms to the existing gas gathering agreement with the applicable party.

6. Income Taxes

As discussed in Note 2, as a master limited partnership, the Partnership is a pass-through entity and not subject to federal income taxes and most state income taxes with the exception of Texas Franchise Tax. For federal and state income tax purposes other than Texas, all income, expenses, gains, losses and tax credits generate flow through to the owners, and accordingly, do not result in a provision for income taxes. Income tax (benefit) expense for the nine months ended September 30, 2009, is as follows:

	Predecessor
	Nine Months Ended September 30, 2009
	(in thousands)
Current	$	—
Deferred		6,341
Total income tax (benefit) expense presented in the Statements of Operations	$	6,341

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Reconciliation of income tax expense at the U.S. Federal Statutory Income Tax Rate to actual tax expense (Statutory Rate Reconciliation) for the nine months ended September 30, 2009, is as follows:

	Predecessor
	Nine Months Ended September 30, 2009
	($ in thousands)
Income tax expense, computed at the statutory rate of 35%	$	(3,862	)
Effect of state income tax, net of federal income tax effect		423
Effect of non-taxable entities		9,780
Total income tax expense (benefit)	$	6,341
Effective tax rate		(57.47	)%

7. Concentration of Credit Risk

Chesapeake and Total are the only customers from whom revenues exceeded 10 percent of consolidated revenues for the years ended December 31, 2011, 2010, and 2009, for the Partnership and its predecessor. The percentage of revenues from Chesapeake, Total and other customers are as follows:

	Years Ended December 31,
	2011			2010			2009
Chesapeake		82.9	%		82.2	%		98.0	%
Total		14.0			14.8			—
Other		3.1			3.0			2.0
Total		100	%		100	%		100	%

Financial instruments that potentially subject the Partnership and its predecessor to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. On December 31, 2011 and 2010, respectively, cash and cash equivalents were invested in a non-interest bearing account and money market funds with investment grade ratings.

8. Property, Plant and Equipment

A summary of the historical cost of the Partnership’s property, plant and equipment is as follows:

	Estimated Useful Lives (Years)		December 31, 2011			December 31, 2010
	($ in thousands)
Gathering systems		20	$	2,954,868		$	2,544,053
Other fixed assets		2 through 39		53,611			41,125
Total property, plant and equipment				3,008,479			2,585,178
Accumulated depreciation				(480,555	)		(358,269	)
Total net, property, plant and equipment			$	2,527,924		$	2,226,909

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Included in gathering systems is $122.6 million and $329.5 million at December 31, 2011 and 2010, respectively, that is not subject to depreciation as the systems were under construction and had not been put into service.

Depreciation expense was $124.7 million, $88.4 million and $19.2 million for the years ended December 31, 2011 and 2010, and three months ended December 31, 2009, respectively, for the Partnership. Depreciation expense was $64.4 million for the nine months ended September 30, 2009, respectively, for the predecessor.

9. Business Combinations

Marcellus.   On December 29, 2011, the Partnership acquired from CMD all of the issued and outstanding common units of Appalachia Midstream for total consideration, which is subject to a customary post-closing working capital adjustment, of $879.3 million, consisting of 9,791,605 common units and $600.0 million in cash that was financed with a draw on the Partnership’s revolving credit facility. The base purchase price of $879.3 million was increased by $7.3 million due to initial working capital adjustments through December 31, 2012. Through the acquisition of Appalachia Midstream, the Partnership operates 100 percent of and owns an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 231 miles of gas gathering pipeline in the Marcellus Shale. The remaining 53 percent interest in these assets is owned primarily by Statoil, Anadarko, Epsilon and Mitsui. Gross throughput for these assets at December 31, 2011, was just over 1.0 Bcf per day (approximately 470 Mmcf per day net to the Partnership). Appalachia Midstream operates the assets under 15-year fixed fee gathering agreements.

The results of operations presented and discussed in this annual report include results of operations from the Appalachia Midstream for the two-day period from closing of the acquisition on December 29, 2011, through December 31, 2011. The Partnership’s interest in the gas gathering systems is accounted for as an equity investment and is included in income from unconsolidated affiliate. For this period, income from unconsolidated affiliate attributable to Marcellus operations was $0.4 million. The purchase price in excess of the value underlying the gas gathering system assets and working capital is approximately $461.2 million and is attributable to customer relationships acquired. This intangible asset will be amortized over a 15 year period on a straight-line basis.

Springridge.   On December 21, 2010, the Partnership completed the Springridge acquisition for $500.0 million in cash that was funded with a draw on the Partnership’s revolving credit facility of approximately $234.0 million plus approximately $266.0 million of cash on hand. The Springridge gathering system is primarily located in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, the Partnership entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication, annual fee redetermination and a minimum volume commitment.

The results of operations presented and discussed in this annual report include results of operations from the Springridge gathering system for the 10-day period from closing of the acquisition on December 21, 2010, through December 31, 2010 and all of 2011. For the 10-day period in 2010, revenues and net loss attributable to Springridge operations were $2.1 million and $1.0 million, respectively. The total purchase price of the Springridge acquisition was allocated as follows: gas gathering system assets of $327.5 million and a customer relationship with a value of $172.5 million. The useful life of the customer relationship acquired is estimated to be 15 years and is amortized on a straight-line basis.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following unaudited pro forma condensed consolidated financial statements for the years ended December 31, 2011 and 2010 are based upon the historical consolidated financial statements of the Partnership and the historical results of operations of the Springridge assets and Appalachia Midstream. The unaudited pro forma condensed consolidated financial statements have been prepared as if Appalachia Midstream acquisition occurred on January 1, 2010, in the case of the unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2011, and as if the Springridge and Appalachia Midstream acquisitions occurred on January 1, 2010, in the case of the unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2010. The pro forma adjustments reflected in the pro forma condensed consolidated financial statements are based upon currently available information and certain assumptions and estimates; therefore, the actual effects of these transactions will differ from the pro forma adjustments. However, the Partnership’s management considers the applied estimates and assumptions to provide a reasonable basis for the presentation of the significant effects of certain transactions that are expected to have a continuing impact on the Partnership. In addition, the Partnership’s management considers the pro forma adjustments to be factually supportable and to appropriately represent the expected impact of items that are directly attributable to the transfer of the Springridge assets and Appalachia Midstream to the Partnership.

The Partnership expects significant throughput volume growth in 2012 as compared to the historical proforma information presented. CMD has committed to pay us quarterly any shortfall between the actual EBITDA from these assets and specified quarterly targets, with the quarterly targets adding to a total of $100 million in 2012 and $150 million in 2013.

	Year Ended December 31, 2011
	Partnership Historical			Appalachia Midstream		Pro Forma Adjustments			Partnership Pro Forma as Adjusted
	(in thousands)
Revenues, including revenue from affiliates	$	565,929		$	—	$	—		$	565,929
Total Operating Expenses		354,139			—		—			354,139
Income from unconsolidated affiliate		433			41,432		(44,974	)  (a)(b)		(3,109	)
Interest expense		(14,884	)		—		(17,543	)  (c)		(32,427	)
Other income		287			—		—			287
Income tax expense		(3,289	)		—		—			(3,289	)
Net income (loss)	$	194,337		$	41,432	$	(62,517	)	$	173,252
Limited partner interest in net income
Net income									$	173,252
Less general partner interest in net income										(3,465	)
Limited partner interest in net income									$	169,787
Net income per common unit – basic and diluted									$	1.15
Net income per subordinated unit – basic and diluted									$	1.15

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

	Year Ended December 31, 2010
	Partnership Historical			Appalachia Midstream		Appalachia Midstream Pro Forma Adjustments			Springridge Assets			Springridge Pro Forma Adjustments			Partnership Pro Forma as Adjusted
	(in thousands)
Revenues, including revenue from affiliates	$	459,153		$	—	$	—		$	53,592		$	—		$	512,745
Total Operating Expenses		259,047			—		—			35,151			12,899	(a)(d)		307,097
Income from unconsolidated affiliates		—			19,978		(44,974	) (a)(b)		—			—			(24,996	)
Interest expense		(2,550	)		—		(23,940	) (c)		(107	)		(6,937	) (e)		(33,534	)
Other income		102			—		—			—			—			102
Income tax expense		(2,431	)		—		—			—			—			(2,431	)
Net income (loss)	$	195,227		$	19,978	$	(68,914	)	$	18,334		$	(19,836	)	$	144,789
Limited partner interest in net income
Net income															$	144,789
Less general partner interest in net income																(2,896	)
Limited partner interest in net income															$	141,893
Net income per common unit – basic and diluted															$	0.96
Net income per subordinated unit – basic and diluted															$	0.96

(a) The amortization of the customer relationship associated with the Springridge and Appalachia Midstream acquisition. The intangible asset is amortized on a straight-line basis over 15 years.

(b) Adjustment to record depreciation expense for the gathering systems acquired in the Appalachia Midstream acquisition to reflect the expense that would have been recorded by the Partnership.

(c) Interest at 2.94 percent and 3.99 percent for the years ended December 31, 2011 and 2010, respectively, on the debt incurred to fund the Appalachia Midstream acquisition. The debt is variable, and a 125 basis point increase in the interest rate would have increased interest expense $7.5 million for both of the years ended December 31, 2011 and 2010, respectively.

(d) The incurrence of incremental general and administrative expense per contractual agreement with Chesapeake. The established terms indicate corporate overhead costs will be charged to the Partnership based on a fee per Mcf of natural gas gathered. The Mcf fee is calculated as the lesser of $0.03/Mcf gathered or actual corporate overhead costs.

(e) Interest at 3.01 percent on the debt incurred to fund the Springridge acquisition. The debt is variable and a 125 basis point increase in the interest rate would have increased interest expense $2.9 million for the twelve months ended December 31, 2010.

Amortization of the intangible asset during each of the next five years is expected to be $11.5 million for Springridge. Amortization expense for Springridge was $11.3 million for the year ended December 31, 2011, with no amortization expense in 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

10. Unconsolidated Affiliates

Marcellus.   On December 29, 2011, the Partnership acquired from CMD, a wholly owned subsidiary of Chesapeake, and certain of its affiliates, all of the issued and outstanding common units of Appalachia Midstream for approximately $879.3 million. Through the acquisition of Appalachia Midstream, the Partnership will operate 100 percent of and own an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 231 miles of gas gathering pipeline in the Marcellus Shale in Pennsylvania and West Virginia. These 10 gathering systems consist of the Liberty, Victory, Rome and Selbyville gas gathering systems and six other smaller gas gathering systems. The remaining 53 percent interest in these assets is owned primarily by Statoil, Anadarko, Epsilon and Mitsui. Appalachia Midstream operates the assets under 15-year fixed fee gathering agreements.

Unconsolidated Affiliates Financial Information.  The following table sets forth summarized financial information of 100 percent of the 10 gas gathering systems in which the Partnership acquired an interest in December 2011, as follows:

	December 31, 2011
Balance Sheet	($ in thousands)
Current assets	$	38,709
Property, plant, and equipment		745,061
Other assets		213
Total assets	$	783,983
Current liabilities	$	13,137
Other liabilities		90,067
Partner’s capital		680,779
Total liabilities and partner’s capital	$	783,983

11. Asset Retirement Obligations

The following table provides a summary of changes in asset retirement obligations, which are included in other liabilities in the accompanying consolidated balance sheets. Revisions in estimates for the periods presented relate primarily to revisions of current cost estimates, inflation rates and/or discount rates.

	Years Ended December 31,
	2011		2010			2009
	(in thousands)
Asset retirement obligations, beginning of period	$	2,878	$	2,850		$	2,714
Additions		131		229			—
Revisions		193		—			—
Accretion expense		207		211			136
Deletions		—		(412	)		—
Asset retirement obligations, end of period	$	3,409	$	2,878		$	2,850

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

12. Long-Term Debt and Interest Expense

The following table presents the Partnership’s outstanding debt as of December 31, 2011 and December 31, 2010 (in thousands):

	December 31, 2011		December 31, 2010
Revolving credit facility	$	712,900	$	249,100
5.875% Senior Notes due April 2021		350,000		—
Total long-term debt	$	1,062,900	$	249,100

Revolving Bank Credit Facility.   On September 30, 2009, the newly created joint venture closed a new $500 million secured revolving bank credit facility to fund capital expenditures associated with the joint venture’s building of additional natural gas gathering systems and for general corporate purposes. At the same time, the predecessor amended and restated its existing revolving bank credit facility to reduce its capacity from $460 million to $250 million, among other changes. The outstanding balance under the predecessor’s credit facility was repaid at the time of the amendment. In conjunction with the establishment of the new facilities, the predecessor expensed $4 million of previously capitalized debt issuance costs associated with this amendment and capitalized $5.7 million associated with the amended $250 million credit facility. The Partnership capitalized $11.5 million of debt issuance costs associated with the $500 million credit facility.

On August 2, 2010, the Partnership amended the $500 million joint venture credit facility. The amended revolving bank credit facility was to mature in July 2015, and provide up to $750.0 million of borrowing capacity, including a sub-limit of $25.0 million for same-day swing line advances and a sub-limit of $50.0 million for letters of credit. In addition, the credit facility contained an accordion feature that allowed the Partnership to increase the available borrowing capacity under the facility up to $1.0 billion, subject to the satisfaction of certain closing conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the credit facility.

On June 10, 2011, the Partnership amended its senior secured revolving credit facility and extended its maturity to June 2016. As amended, the credit facility provides up to $800 million of borrowing capacity and includes a sub-limit of $50 million for same-day swing line advances and a sub-limit of $50 million for letters of credit. In addition, the credit facility contains an accordion feature that allows the Partnership to increase the available borrowing capacity under the facility up to $1 billion, subject to the satisfaction of certain closing conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the credit facility.

On December 20, 2011 the Partnership amended its revolving credit facility to increase total borrowing capacity. The revolving credit facility, as amended to date, provides the Partnership up to $1 billion of borrowing capacity and includes a sub-limit up to $50 million for same-day swing line advances and a sub-limit up to $50 million for letters of credit. In addition, the revolving credit facility contains an accordion feature that allows the Partnership to increase the available borrowing capacity under the facility up to $1.25 billion, subject to the satisfaction of certain conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the facility. The revolving credit facility matures in June 2016. As of December 31, 2011 the Partnership had approximately $712.9 million of borrowings outstanding under its revolving credit facility.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

Borrowings under the revolving credit facility are available to fund working capital, finance capital expenditures and acquisitions, provide for the issuance of letters of credit and for general partnership purposes. The revolving credit facility is secured by all of the Partnership’s assets, and loans thereunder (other than swing line loans) bear interest at the Partnership’s option at either (i) the greater of (a) the reference rate of Wells Fargo Bank, NA, (b) the federal funds effective rate plus 0.50 percent or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (LIBOR), plus 1.00 percent, each of which is subject to a margin that varies from 0.625 percent to 1.50 percent per annum, according to the Partnership’s leverage ratio (as defined in the agreement), or (ii) the Eurodollar rate plus a margin that varies from 1.625 percent to 2.50 percent per annum, according to the Partnership’s leverage ratio. If the Partnership reaches investment grade status, the Partnership will have the option to release the security under the credit facility and amounts borrowed will bear interest under a specified ratings-based pricing grid. The unused portion of the credit facility is subject to commitment fees of (a) 0.25 percent to 0.40 percent per annum while the Partnership is subject to the leverage-based pricing grid, according to the Partnership’s leverage ratio and (b) 0.20 percent to 0.35 percent per annum while the Partnership is subject to the ratings-based pricing grid, according to its senior unsecured long-term debt ratings.

Additionally, the revolving credit facility contains various covenants and restrictive provisions which limit the Partnership and its subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of the Partnership’s assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness. If the Partnership fails to perform its obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. The revolving credit facility also has cross default provisions that apply to any other indebtedness the Partnership may have with an outstanding principal amount in excess of $15 million.

The revolving credit facility agreement contains certain negative covenants that (i) limit the Partnership’s ability, as well as the ability of certain of its subsidiaries, among other things, to enter into hedging arrangements and create liens and (ii) require the Partnership to maintain a consolidated leverage ratio, and an EBITDA to interest expense ratio, in each case as described in the credit facility agreement. The revolving credit facility agreement also provides for the discontinuance of the requirement for the Partnership to maintain the EBITDA to interest expense ratio if the Partnership reaches investment grade status. The revolving credit facility agreement also requires the Partnership to maintain a consolidated leverage ratio of 5.0 to 1.0 (or 5.5 to 1.0 during an approximate two-quarter period following the completion of certain acquisitions). The Partnership was in compliance with all covenants under the agreement at December 31, 2011.

Senior Notes.   On April 19, 2011, the Partnership and CHKM Finance Corp., a wholly owned subsidiary of Chesapeake MLP Operating, L.L.C., completed a private placement of $350.0 million in aggregate principal amount of 5.875 percent senior notes due 2021 (the “2021 Notes”). The Partnership used a portion of the net proceeds to repay borrowings outstanding under its revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $7.8 million are being amortized over the life of the 2021 Notes.

The 2021 Notes will mature on April 15, 2021 and interest is payable on the 2021 Notes on April 15 and October 15 of each year, beginning on October 15, 2011. The Partnership has the option

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

to redeem all or a portion of the 2021 Notes at any time on or after April 15, 2015, at the redemption price specified in the indenture, plus accrued and unpaid interest. The Partnership may also redeem the 2021 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to April 15, 2015. In addition, the Partnership may redeem up to 35 percent of the 2021 Notes prior to April 15, 2014 under certain circumstances with the net cash proceeds from certain equity offerings. The Indenture contains covenants that, among other things, limit the Partnership’s ability and the ability of certain of its subsidiaries to: (1) sell assets including equity interests in its subsidiaries; (2) pay distributions on, redeem or purchase its units, or redeem or purchase its subordinated debt; (3) make investments; (4) incur or guarantee additional indebtedness or issue preferred units; (5) create or incur certain liens; (6) enter into agreements that restrict distributions or other payments from certain subsidiaries to the Partnership; (7) consolidate, merge or transfer all or substantially all of its assets; (8) engage in transactions with affiliates; and (9) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the 2021 Notes achieve an investment grade rating from either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no default, as defined in the Indenture, has occurred or is continuing, many of these covenants will terminate.

On January 11, 2012, the Partnership and CHKM Finance Corp. completed a private placement of $750.0 million in aggregate principal amount of 6.125 percent senior notes due 2022. See Note 15 for discussion regarding the transaction.

The Partnership, as the parent company, has no independent assets or operations. The Partnership’s operations are conducted by its subsidiaries through its operating company subsidiary, Chesapeake MLP Operating, L.L.C. Each of Chesapeake MLP Operating, L.L.C. and the Partnership’s other subsidiaries is a guarantor, other than CHKM Finance Corp., an indirect wholly owned subsidiary of the Partnership whose sole purpose is to act as co-issuer of any debt securities. Each guarantor is a wholly owned subsidiary of the Partnership. The guarantees registered under the registration statement are full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the Indenture. There are no significant restrictions on the ability of the Partnership or any guarantor to obtain funds from its subsidiaries by dividend or loan. None of the assets of the Partnership or a guarantor represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.

Fair Value.   Estimated fair values are determined by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. Based on the borrowing rates available at December 31, 2011 for debt with similar terms and maturities, the carrying value of long-term debt approximates its fair value.

Capitalized Interest.   Interest expense was net of capitalized interest of $9.5 million, $2.6 million, $0.3 million, and $6.5 million for the years ended December 31, 2011 and 2010, three months ended December 31, 2009, and nine months ended September 30, 2009, respectively, for the Partnership and the predecessor.

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CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

13. Commitments and Contingencies

Environmental obligations.   The Partnership is subject to various environmental-remediation and reclamation obligations arising from federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. Management believes there are currently no such matters that will have a material effect on the Partnership’s results of operations, cash flows or financial position and has not recorded any liability in these financial statements.

Litigation and legal proceedings.   From time to time, the Partnership is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceedings for which a final disposition could have a material effect on the Partnership’s results of operations, cash flows or financial position. There was not an accrual for legal contingencies as of December 31, 2011 or 2010.

Lease commitments.  Certain property, equipment and operating facilities are leased under various operating leases. Costs are also incurred associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations.

Rental expense related to leases was $60.7 million, $50.1 million, $11.7 million, and $48.2 million for the years ended December 31, 2011 and 2010, three months ended December 31, 2009, nine months ended September 30, 2009, respectively, for the Partnership and the predecessor. The Partnership’s remaining contractual lease obligations as of December 31, 2011 represent obligations with an affiliate of Chesapeake for compression equipment as compression services are needed to support pipeline that is being placed in service in future periods.

Future minimum rental payments due under operating leases as of December 31, 2011 are as follows:

	(in thousands)
2012	$	36,549
2013		23,053
2014		14,848
2015		4,049
2016		997
Thereafter		—
Future minimum lease payments(1)	$	79,496

⁽¹⁾  Includes the Partnership’s minimum rental payments for Appalachia Midstream acquired on December 29, 2011.

14. Recently Issued Accounting Standards

The Financial Accounting Standards Board (“FASB”) recently issued the following standard which the Partnership reviewed to determine the potential impact on its financial statements upon adoption.

In December 2010, the FASB issued guidance on disclosure of supplementary pro forma information for business combinations. The guidance specifies that if a public entity presents

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CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The guidance also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, non-recurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenues and earnings. These amendments are effective prospectively for business combinations with an acquisition date on or after December 15, 2010.

15. Subsequent Events

On January 11, 2012, the Partnership and CHKM Finance Corp. completed a private placement of $750.0 million in aggregate principal amount of 6.125 percent senior notes due 2022. The Partnership used a portion of the net proceeds to repay all borrowings outstanding under its revolving credit facility and used the balance for general partnership purposes.

On January 27, 2012, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.3900 per unit, or $58.9 million in aggregate. The cash distribution was paid on February 14, 2012 to unitholders of record at the close of business on February 7, 2012.

16. Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2011 and 2010 are as follows ($ in thousands except per share data):

	Quarters Ended
	March 31, 2011		June 30, 2011		September 30, 2011		December 31, 2011
Total revenues	$	123,529	$	133,217	$	140,105	$	169,078
Gross profit(a)		80,968		88,933		96,872		122,305
Net income		38,776		41,083		48,173		66,305
Net income attributable to Chesapeake Midstream Partners, L.P.(b)		38,776		41,083		48,173		66,305
Net income per limited partner unit(b)	$	0.27	$	0.29	$	0.34	$	0.46
	Quarters Ended
	March 31, 2010		June 30, 2010		September 30, 2010		December 31, 2010
Total revenues	$	95,386	$	101,239	$	100,060	$	162,468
Gross profit(a)		64,693		68,854		65,966		126,347
Net income		34,914		37,017		33,414		89,882
Net income attributable to Chesapeake Midstream Partners, L.P.(b)		n/a		n/a		19,514		89,882
Net income per limited partner unit(b)	$	n/a	$	n/a	$	0.14	$	0.64

^(a)  Total revenue less operating costs.

^(b)  Reflective of general and limited partner interest in net income since closing the Partnership’s IPO on August 3, 2010. See Note 4 to the consolidated financial statements.

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ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

ITEM 9A. Controls and Procedures

As required by Rules 13a-15(b) and 15d-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure. Based upon the evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures were effective at a reasonable level of assurance as of December 31, 2011.

Changes in Internal Control over Financial Reporting

No changes in the Partnership’s internal control over financial reporting occurred during the quarter ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Management’s annual report on internal control over financial reporting and the audit report on our internal control over financial reporting of our independent registered public accounting firm are included in Item 8 of this report.

ITEM 9B. Other Information

Not applicable.

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PART III

ITEM 10. Directors, Executive Officers and Corporate Governance

Management of the Partnership

As a limited partnership, we have no directors or officers. Instead, Chesapeake Midstream GP, L.L.C., our general partner, manages our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it.

The directors of our general partner oversee our operations. Chesapeake Midstream Ventures, which is jointly and equally owned by Chesapeake and GIP, is the sole member of our general partner and has the right to appoint our general partner’s entire board of directors. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. Our general partner has seven directors, two of whom are designated by Chesapeake, two of whom are designated by GIP and three of whom are independent as defined under the independence standards established by the NYSE and the Exchange Act. Our general partner’s board of directors has affirmatively determined that David A. Daberko, Philip L. Fredrickson and Suedeen G. Kelly satisfy the NYSE and SEC requirements for independence for directors. The NYSE does not require a listed publicly traded partnership, like us, to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating/corporate governance committee, although our general partner’s board of directors has established an audit committee, a conflicts committee and a compensation committee.

The officers of our general partner manage and conduct our operations. All of the executive officers of our general partner, other than J. Mike Stice, the Chief Executive Officer of our general partner, devote all of their time to manage and conduct our operations. Mr. Stice allocates his time between managing our business and affairs and certain business and affairs of Chesapeake and, as such, may face a conflict regarding the allocation of his time between our business and other business interests of Chesapeake. In 2011, Mr. Stice devoted approximately half of his time to our business, although we expect the amount of time that he devotes may increase or decrease in the future as our business develops. The officers of our general partner and other Chesapeake employees operate our business and provide us with general and administrative services pursuant to the services agreement and the employee secondment agreement and, in the case of Mr. Stice, the shared services agreement, each as described in “Item 13. Certain Relationships and Related Transactions, and Director Independence—Agreements with Affiliates—Employee Secondment Agreement,” “—Services Agreement” and “—Shared Services Agreement.”

Our general partner does not receive any management fee or other compensation for its management of our Partnership under the omnibus agreement, the services agreement, the employee secondment agreement or otherwise. Under the services agreement, Chesapeake performs centralized corporate functions for us. In return for such general and administrative services, our general partner has agreed to reimburse Chesapeake on a monthly basis for the time and materials actually spent in providing general and administrative support to our operations. Our reimbursement to Chesapeake of such general and administrative expenses in any given month is subject to a cap in an amount equal to $0.03065 per Mcf multiplied by the volume (measured in Mcf) of natural gas that we gather, transport or process in such month. The $0.03065 per Mcf cap is subject to an annual upward adjustment on October 1st of each year equal to 50 percent of any increase in the Consumer Price Index, and, subject to receipt of requisite approvals, such cap may be further adjusted to reflect changes in the general and administrative services provided by Chesapeake relating to new laws or

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accounting rules that are implemented. In addition, under the employee secondment agreement, specified employees of Chesapeake are seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Our general partner, subject to specified exceptions and limitations, reimburses Chesapeake on a monthly basis for substantially all costs and expenses it incurs relating to such seconded employees. Please read “Item 13. Certain Relationships and Related Transactions, and Director Independence—Agreements with Affiliates—Employee Secondment Agreement.”

Directors and Executive Officers

The following table shows information regarding the current executive officers and directors of our general partner. Directors are appointed for a term of one year. The directors hold office until their successors have been duly elected and qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board of directors. There are no family relationships among any of our general partner’s directors or executive officers.

Name	Age	Position with Chesapeake Midstream GP, L.L.C.
J. Mike Stice	52	Chief Executive Officer
David C. Shiels	46	Chief Financial Officer
Robert S. Purgason	55	Chief Operating Officer
David A. Daberko	66	Chairman of the Board
Domenic J. Dell’Osso, Jr.	35	Director
Philip L. Frederickson	55	Director
Matthew C. Harris	51	Director
Suedeen G. Kelly	60	Director
Aubrey K. McClendon	52	Director
William A. Woodburn	61	Director

J. Mike Stice, Ed.D. has served as Chief Executive Officer of our general partner since January 2010. Mr. Stice was appointed Senior Vice President—Natural Gas Projects of Chesapeake Energy Corporation and President and Chief Operating Officer of Chesapeake’s primary midstream subsidiaries in November 2008. Prior to joining Chesapeake, Mr. Stice spent 27 years with ConocoPhillips and its predecessor companies, where he most recently served as President of ConocoPhillips Qatar, responsible for the development, management and construction of natural gas liquefaction and regasification (LNG) projects. While at ConocoPhillips, he also served as Vice President of Global Gas LNG, as President of Gas and Power and as President of Energy Solutions in addition to other roles in ConocoPhillips’ midstream business units. Mr. Stice graduated from the University of Oklahoma in 1981, from Stanford University in 1995 and from George Washington University in 2011.

David C. Shiels has served as Chief Financial Officer of our general partner since January 2010. For 13 years prior to joining our general partner, Mr. Shiels held multiple regional chief financial officer roles with subsidiaries of General Electric. Mr. Shiels most recently served as Chief Financial Officer of GE Security Americas. Prior to General Electric, Mr. Shiels spent nine years with Conoco, Inc. in various finance and operational roles. Mr. Shiels graduated from Michigan State University in 1988.

Robert S. Purgason has served as Chief Operating Officer of our general partner since January 2010. Prior to joining our general partner, Mr. Purgason spent five years at Crosstex Energy Services, L.P. and was promoted to Senior Vice President—Chief Operating Officer in November 2006. Prior to Crosstex, Mr. Purgason spent 19 years with The Williams Companies in various senior business development and operational roles. Mr. Purgason began his career at Perry Gas Companies in Odessa, Texas working in all facets of the natural gas treating business. Mr. Purgason graduated from the University of Oklahoma in 1978.

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David A. Daberko has served as a director of our general partner since August 2010 and as Chairman of our general partner’s board of directors since December 2010. Mr. Daberko is the retired Chairman and Chief Executive Officer of National City Corporation (NYSE: NCC) where he worked for 39 years. He joined National City Bank in 1968 as a management trainee and held a number of management positions within the company. In 1985, he led the assimilation of the former BancOhio National Bank into National City Bank, Columbus. In 1987, Mr. Daberko was elected Deputy Chairman of National City Corporation and President of National City Bank in Cleveland. He served as President and Chief Operating Officer from 1993 until 1995 when he was named Chairman and Chief Executive Officer. He retired as Chief Executive Officer in June 2007 and as Chairman in December 2007. Mr. Daberko also serves on the board of directors of RPM International, Inc. (NYSE: RPM) and Marathon Petroleum Corporation (NYSE: MPC). He is a trustee of Case Western Reserve University, University Hospitals Health System and Hawken School. Mr. Daberko also previously served, within the last five years, as a director of National City Corporation and OMNOVA Solutions, Inc. Mr. Daberko graduated from Denison University in 1967 and from Case Western Reserve University in 1970. We believe that Mr. Daberko’s extensive financial industry background, particularly the leadership and management skills he acquired while serving as a chief executive officer, brings important experience and skill to the board.

Domenic J. (“Nick”) Dell’Osso, Jr. has served as a director of our general partner since June 2011. Mr. Dell’Osso has been Executive Vice President and Chief Financial Officer of Chesapeake since November 2010. Mr. Dell’Osso served as Vice President—Finance of Chesapeake and Chief Financial Officer of Chesapeake’s wholly owned midstream subsidiary, Chesapeake Midstream Development, L.P., from August 2008 to November 2010. Prior to joining Chesapeake, Mr. Dell’Osso was an energy investment banker with Jefferies & Co. from 2006 to August 2008 and Banc of America Securities from 2004 to 2006. Mr. Dell’Osso graduated from Boston College in 1998 and from the University of Texas at Austin in 2003. We believe that Mr. Dell’Osso’s experience in the energy industry, particularly his financial strategy and oversight expertise, brings important experience and skill to the board.

Philip L. Frederickson has served as a director of our general partner since August 2010. Mr. Frederickson retired from ConocoPhillips (NYSE: COP) after 29 years of service with the company. At the time of his retirement he was Executive Vice President Planning, Strategy and Corporate Affairs. He also served as a board member for Chevron Phillips Chemical and DCP Midstream. Mr. Frederickson joined Conoco in 1978 and held several senior positions in the United States and Europe, including General Manager, Strategy and Business Development, Refining and Marketing Europe; Managing Director, Conoco Ireland; General Manager, Refining and Marketing, Rocky Mountain region; General Manager, Strategy and Portfolio Management, Upstream; and Vice President, Business Development. Mr. Frederickson was Senior Vice President of Corporate Strategy and Business Development for Conoco Inc. from 2001 to 2002. Following the announcement of the merger of Conoco and Phillips in 2001, Mr. Frederickson was named integration lead to coordinate the merger transition and in 2002 was made Executive Vice President, Commercial, of ConocoPhillips. Mr. Frederickson serves as a board member for Rosetta Resources Inc. (NASDAQ: ROSE), Sunoco Logistics (NYSE: SXL) and the Yellowstone Park Foundation and is a member of the Texas Tech University Engineering Dean’s Council. Mr. Frederickson graduated from Texas Tech University in 1978. We believe that Mr. Frederickson’s extensive energy industry background, particularly his expertise in corporate strategy and business development, brings important experience and skill to the board.

Matthew C. Harris has served as a director of our general partner since January 2010. Mr. Harris is currently a partner of GIP leading GIP’s energy/waste industry investment team globally. He is a member of the board of GIP and of its Investment and Portfolio Valuation Committees. Prior to the formation of GIP in 2006, Mr. Harris was a Managing Director in the Investment Banking Department at

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Credit Suisse. Most recently, he was Co-Head of the Global Energy Group and Head of the EMEA Emerging Markets Group. Prior to 2003, Mr. Harris was a senior member of the Mergers and Acquisitions Group and served as Co-Head of Americas M&A. From 1984 to 1994, he was a senior member of the Mergers and Acquisitions Group of Kidder Peabody & Co. Incorporated. Mr. Harris is a director of the GIP portfolio companies Biffa and Ruby Pipeline Holding Company LLC. Mr. Harris graduated from the University of California at Los Angeles in 1984. We believe that Mr. Harris’ extensive energy industry background, particularly his expertise in mergers and acquisitions, brings important experience and skill to the board.

Suedeen G. Kelly has served as a director of our general partner since August 2010. Ms. Kelly has been a Partner in the law firm Patton Boggs LLP since April 2010. She is a former Commissioner of the Federal Energy Regulatory Commission. Ms. Kelly was nominated by both Presidents Bush and Obama to three terms as Commissioner of the Federal Energy Regulatory Commission from 2003 to 2009. In 2000, she worked as Regulatory Counsel to the California Independent System Operator. In 1999, she was an aide to U.S. Senator Jeff Bingaman. She was a full-time professor at the University of New Mexico School of Law from 1986 to 1999, where she taught energy and public utility law. Before joining the faculty, she was Chair of the New Mexico Public Service Commission. Ms. Kelly has also been in the private practice of law with the Modrall Law Firm; Luebben, Hughes & Kelly; Ruckelshaus, Beveridge, Fairbanks & Diamond; and the Natural Resources Defense Council. Mrs. Kelly graduated from the University of Rochester in 1973 and from Cornell Law School in 1976. We believe that Ms. Kelly’s extensive energy industry background, particularly her expertise in federal and state regulatory matters, brings important experience and skill to the board.

Aubrey K. McClendon has served as a director of our general partner since January 2010. Mr. McClendon has served as Chairman of the Board, Chief Executive Officer and a director of Chesapeake since co-founding Chesapeake in 1989. From 1982 to 1989, Mr. McClendon was an independent producer of oil and natural gas. Mr. McClendon graduated from Duke University in 1981. We believe that Mr. McClendon’s extensive energy industry background and relationship with Chesapeake, particularly his leadership skills in serving as Chairman of the Board and Chief Executive Officer of Chesapeake and his instrumental role in the formulation and promotion of national and local initiatives that advocate for American natural gas as the best solution for our nation’s future energy needs, bring important experience and skill to the board.

William A. Woodburn has served as a director of our general partner since January 2010. Mr. Woodburn is currently a partner of GIP and oversees GIP’s operating team. Mr. Woodburn is a member of the board of GIP and of its Investment and Portfolio Valuation Committees and serves as chairman of its Portfolio Committee. Prior to the formation of GIP in 2006, Mr. Woodburn was the President and Chief Executive Officer of GE Infrastructure, which encompassed Water Technologies, Security and Sensing Growth Platforms and GE Fanuc Automation. Prior to his tenure at GE Infrastructure, Mr. Woodburn served as President and Chief Executive Officer of GE Specialty Materials. From 2000 to 2001, Mr. Woodburn served as Executive Vice President and member of the Office of Chief Executive Officer at GE Capital and served as a member of the board of GE Capital from 2000 to 2001. Mr. Woodburn joined General Electric in 1984 and held leadership positions at GE Lighting (1984-1993) and GE Superabrasives (1994-2000). Prior to joining General Electric, Mr. Woodburn held process engineering and marketing positions at Union Carbide’s Linde Division for five years and was an engagement manager at McKinsey & Company for four years focusing on energy and transportation industries. Mr. Woodburn is a director of the GIP portfolio companies Biffa, Gatwick Airport Limited and Terra-Gen Power Holdings, LLC. Mr. Woodburn graduated from the U.S. Merchant Marine Academy in 1973 and from Northwestern University in 1975. We believe that Mr. Woodburn’s extensive energy industry background, particularly the leadership skills he developed while serving in several executive positions, brings important experience and skill to the board.

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Board of Directors

Committees

Our general partner’s board of directors has three standing committees: the audit committee, conflicts committee and compensation committee.

Audit Committee.  The audit committee consists of three independent members of our general partner’s board of directors, Messrs. Daberko and Frederickson and Ms. Kelly. Mr. Daberko is the current chairman of the audit committee. The members of the audit committee must meet the independence and experience standards established by the NYSE and the Exchange Act. The board has determined that each member of the audit committee is independent under the NYSE listing standards and the Exchange Act. The audit committee held seven meetings in 2011.

Mr. Daberko has been designated by our general partner’s board of directors as the “audit committee financial expert” meeting the requirements promulgated by the SEC based upon his education and employment experience as more fully detailed in Mr. Daberko’s biography set forth below.

The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and Partnership policies and controls. The audit committee has the sole authority to, among other things, (i) retain and terminate our independent registered public accounting firm, (ii) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm and (iii) establish policies and procedures for the pre-approval of all non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has been given unrestricted access to the audit committee and our management, as necessary.

Conflicts Committee.  The conflicts committee consists of three independent members of our general partner’s board of directors, Messrs. Daberko and Frederickson and Ms. Kelly. Mr. Frederickson is the current chairman of the conflicts committee. The conflicts committee reviews specific matters that the board believes may involve conflicts of interest (including certain transactions with Chesapeake, GIP and/or Chesapeake Midstream Ventures) and which it determines to submit to the conflicts committee for review. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Chesapeake, GIP and/or Chesapeake Midstream Ventures, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. The conflicts committee held 10 meetings in 2011.

Compensation Committee.  The compensation committee consists of three members of our general partner’s board of directors, Messrs. Harris and Dell’Osso and Ms. Kelly. Ms. Kelly is the current chairman of the compensation committee. The objectives of the compensation committee are to develop an executive compensation system that is competitive with the Partnership’s peers and encourages both short-term and long-term performance in a manner beneficial to the Partnership and its operations. In fulfilling this objective, the compensation committee oversees compensation decisions for the officers of our general partner and administers the LTIP with respect to the officers of

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our general partner, selecting individuals to be granted equity-based awards from among those eligible to participate. The compensation committee has adopted a charter, which has been ratified and approved by the board of directors. The compensation committee held three meetings in 2011.

Director Qualifications

Evaluation of director candidates includes an assessment of whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct the affairs and business of the Partnership, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

We have no minimum qualifications for director candidates. In general, however, we review and evaluate both incumbent and potential new directors in an effort to achieve diversity of skills and experience among our directors and in light of the following criteria:

• experience in business, government, education, technology or public interests;

• high-level managerial experience in large organizations;

• breadth of knowledge regarding our business or industry;

• specific skills, experience or expertise related to an area of importance to us, such as energy production, consumption, distribution or transportation, government, policy, finance or law;

• moral character and integrity;

• commitment to our unitholders’ interests;

• ability to provide insights and practical wisdom based on experience and expertise;

• ability to read and understand financial statements; and

• ability to devote the time necessary to carry out the duties of a director, including attendance at meetings and consultation on Partnership matters.

Qualified candidates for nomination to the board are considered without regard to race, color, religion, gender, ancestry or national origin.

Board Leadership Structure and Role in Risk Oversight

Mr. Daberko currently serves as chairman of our general partner’s board of directors. Our general partner’s board of directors believes that no single organizational structure is best and most effective in all circumstances. Accordingly, the board retains the flexibility to determine the organizational structure that best enables the Partnership to confront the challenges and risks it faces. Although our general partner’s chief executive officer currently does not serve as a member of our general partner’s board of directors, we have no policy prohibiting any current or future executive officer from serving as a member of the board, including as its chairman. Members of our general partner’s board of directors are designated or elected by the sole member of our general partner, Chesapeake Midstream Ventures.

It is management’s responsibility, subject to the oversight of our general partner’s board of directors, to monitor and, to the extent possible, mitigate the negative impact of uncertainty in the business environment on our operations and our financial objectives. Our general partner maintains an enterprise risk management (“ERM”) program overseen by its management-level Risk Management Committee, which is comprised of our general partner’s Chief Operating Officer, Chesapeake’s Vice President of Risk Management, our general partner’s Director of Environmental Health and Safety, and our general partner’s Lead Counsel. Significant risks and the possible approaches to mitigate such

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risks are reviewed by the Risk Management Committee at periodic meetings and presented to the board’s risk management director to assess the impact on our strategic objectives and risk tolerance levels. Ms. Kelly currently serves as the board’s risk management director and updates the board on a quarterly basis regarding any risk management developments. In addition, the audit committee is responsible for overseeing the Partnership’s financial risks. A number of other processes at the board level support our risk management effort, including board reviews of our long-term strategic plans, capital budget and certain capital projects, interest rate hedging policy, significant acquisitions and divestitures, capital markets transactions and the delegation of authority to our management. Our Compensation Committee does not believe our compensation programs encourage excessive or inappropriate risk taking.

Meeting of Non-Management Directors and Communications with Directors

At each quarterly meeting of our general partner’s board of directors, all of the directors meet in an executive session without management participation. At least annually, our independent directors meet in an additional executive session without management participation or participation by non-independent directors. The chairman of the board of directors, Mr. Daberko, presides over all executive sessions.

Unitholders or interested parties may communicate with any and all members of our board, including our non-management directors, or any committee of our board, by transmitting correspondence by mail or facsimile addressed to one or more directors by name or to the chairman of the board or any committee of the board at the following address or fax number: Name of the Director(s), c/o Marc D. Rome, Assistant Corporate Secretary, Chesapeake Midstream Partners, L.P., 900 N.W. 63rd Street, Oklahoma City, Oklahoma 73118, or to fax number (405) 849-6282.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our general partner’s board of directors and executive officers, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC, and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by the SEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they file with the SEC.

To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all reporting obligations of our general partner’s officers, directors and greater than 10 percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2011.

Code of Ethics, Corporate Governance Guidelines and Board Committee Charters

Our general partner has adopted a Code of Business Conduct and Ethics (the “Code of Ethics”) that applies to the directors, officers and employees of our general partner. If the general partner amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, we will disclose the information on our website. Our general partner has also adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance.

We make available free of charge, within the “Corporate Governance” subsection of the “Investors” section of our website at http://www.chkm.com, and in print to any unitholder who so requests, the Code of Ethics and our Corporate Governance Guidelines, audit committee charter,

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conflicts committee charter and compensation committee charter. Requests for print copies may be directed to Dave Shiels at dave.shiels@chk.com or to Investor Relations, Chesapeake Midstream Partners, L.P., 900 N.W. 63rd Street, Oklahoma City, Oklahoma 73118, or by telephone at (405) 935-6224. We will post on our website all waivers to or amendments of the Code of Ethics, which are required to be disclosed by applicable law and the NYSE’s Corporate Governance Listing Standards. The information contained on, or connected to, our website is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

ITEM 11. Executive Compensation

Compensation Discussion and Analysis

Named Executive Officers

This Compensation Discussion and Analysis describes the compensation system for our named executive officers for 2011 consisting of the following individuals: (1) J. Michael Stice, Chief Executive Officer; (2) David C. Shiels, Chief Financial Officer; and (3) Robert S. Purgason, Chief Operating Officer.

Overview

Our general partner manages our operations and activities, and it, together with its board of directors and officers, makes decisions on our behalf. However, Chesapeake directly employs all of the persons responsible for managing our business, including the named executive officers. Our reimbursement for the compensation earned by the named executive officers is governed by, and subject to the limitations contained in, the services agreement, the employee secondment agreement and the shared services agreement. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Shared Services Agreement.” The compensation expense allocated to us in 2011 with respect to Mr. Stice was 50 percent of his total compensation and with respect to Messrs. Shiels and Purgason was 100 percent of their total compensation. Such allocation with respect to Mr. Stice was calculated in accordance with the shared services agreement and based in part on Mr. Stice’s good faith estimate of the percentage of time he spent providing services to the Partnership. Accordingly, the compensation disclosed in this report as paid or awarded to Mr. Stice in 2011 reflects only the portion of compensation expense that is or will be payable by us pursuant to the terms of the shared services agreement.

The following discussion relating to compensation paid to the named executive officers by Chesapeake for their service to us is based on information provided to us by Chesapeake (except for the discussion below related to our Long-Term Incentive Plan (“LTIP”) and Management Incentive Compensation Plan (“MICP”)) and does not purport to be a complete discussion and analysis of Chesapeake’s executive compensation philosophy and practices.

Compensation Design and Process

Our compensation system was designed by Chesapeake to:

• attract, retain and motivate executive officers with the competence, knowledge, leadership skills and experience to grow the Partnership’s profitability;

• align the interests of the executive officers with the interests of our unitholders by basing a significant majority of each executive officer’s total compensation on individual and Partnership performance; and

• encourage both a short-term and long-term focus, while discouraging excessive risk taking.

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Chesapeake has entered into employment agreements with our named executive officers, which are described below. The employment agreements are the primary basis for the current compensation mix and levels for each of the named executive officers and reflect Chesapeake’s comprehensive approach to executive compensation. In addition, in 2011 Chesapeake reviewed each named executive officer’s performance twice. Chesapeake believes that more frequent performance reviews (rather than year-end to year-end) accurately reflect the dynamic nature of our industry and permit Chesapeake to better understand the business issues facing the named executive officers on an ongoing basis. This review consisted of a subjective assessment of the overall performance of the named executive officer team and the role and relative contribution of each of its members. In its assessment of the performance of each named executive officer, Chesapeake considered the following:

Individual Performance	Partnership Performance	Intangibles
•       Contributions to the development and execution of the Partnership’s business plans and strategies (including contributions that are expected to provide substantial benefit to the organization in future periods) •       Performance of the relevant department or functional unit •       Level of responsibility •       Longevity with the Partnership	•       Overall performance of the Partnership, including progress made with respect to operational results, risk management activities, asset acquisitions and asset monetizations •       Financial performance as measured by cash flow, net income, cost of capital, general and administrative costs and common unit price performance	•       Leadership ability •       Demonstrated commitment to the organization •       Motivational skills •       Attitude •       Work ethic

As part of this review, Mr. Stice provides recommendations to Chesapeake and the compensation committee of the board of directors of our general partner with respect to the compensation levels of Messrs. Shiels and Purgason based on their respective employment agreements as well as a comprehensive, subjective evaluation of the Partnership’s performance and their individual performance. Chesapeake’s management provides a similar recommendation to the compensation committee of the board of directors of our general partner with respect to Mr. Stice. The compensation committee of the board of directors of our general partner reviews and approves the total compensation for the named executive officers. Awards to the named executive officers under our LTIP and MICP are also expressly approved by the board of directors of our general partner. With respect to Mr. Stice, Chesapeake’s assessment of his performance also included consideration of his position as a Senior Vice President with Chesapeake and his role and relative contribution to Chesapeake; however, for purposes of this discussion we have focused on the portion of his compensation for which the Partnership has reimbursed Chesapeake.

Elements and Mix of Compensation

Chesapeake provided short-term compensation in the form of base salaries and cash bonuses and long-term compensation in the form of equity awards and 401(k) matching contributions (paid in Chesapeake stock). Additionally, Chesapeake’s more highly-compensated employees, including the named executive officers, were eligible to defer certain compensation through a nonqualified deferred compensation program and to receive certain perquisites.

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Cash Salary and Bonuses

The base salary levels of the named executive officers are intended to reflect each named executive officer’s base level of responsibility, leadership, tenure and contribution to the success and profitability of the organization. Base salaries tend to be less variable over time and are intended to contribute less to total compensation than incentive awards. Cash bonuses were intended to provide incentives based on a subjective performance assessment over a shorter period of time than the equity compensation listed below.

Equity-Based Compensation

The equity-based compensation of the named executive officers was intended to provide incentives for long-term performance that increases unitholder value by aligning the interests of the unitholders and the named executive officers. Equity awards were granted to the named executive officers in January and July as part of Chesapeake’s semi-annual review of employee compensation. Each of Messrs. Stice, Shiels and Purgason received phantom unit awards under our LTIP, which is described below under “Long-Term Incentive Plan”. Under the terms of the employee secondment agreement, Messrs. Shiels and Purgason were not eligible to receive Chesapeake restricted stock awards, and, instead, their interests in the MICP and phantom unit awards that were made under our LTIP provided them with equity-related incentive compensation. Mr. Stice also received Chesapeake restricted stock awards. Under the shared services agreement concerning Mr. Stice, we are required to reimburse Chesapeake with respect to equity awards called for under the terms of Mr. Stice’s employment agreement but not any discretionary equity awards, unless agreed to by GIP.

Management Incentive Compensation Plan

Chesapeake Midstream Management, L.L.C. adopted the MICP, which provides incentive compensation awards, consisting of two components, to key members of management who have been designated as participants by our general partner. Messrs. Shiels and Purgason were each granted an MICP award in 2010.

The first component of the award is an annual cash bonus based on “excess” cash distributions made by us each fiscal year above an annual target amount during a five-year period (the “Excess Return Component”). A participant’s Excess Return Component will generally be calculated by multiplying the “excess” distribution amount for an applicable year (the amount of distributions that were made over “target” for that year) by the participant’s participation percentage assigned to him at the time of grant, by the annual payment percentage that is also assigned to the officer at the time of the grant. The Excess Return Component determined to be payable to a participant with respect to a specified fiscal year (if any) is paid pro-rata that year and in each of the years then remaining in the five-year period, provided the participant continues to be employed by us or an affiliate until the payment date.

The second component is based on an increase in value of our common units at the end of the five-year period and is paid at the end of the five-year period (the “Equity Uplift Component”), unless a change of control occurs prior to that five-year period, at which time the award would be paid upon that change of control. The Equity Uplift Component is calculated by multiplying the “equity uplift value,” if any, by the participants “equity uplift value percentage.” The “equity uplift value” is defined as the excess of the value of our units on the payment date over the value of our units on our IPO date (which was $21.00), multiplied by the number of our outstanding units on the payment date. Each participant’s “equity uplift value percentage” is assigned pursuant to an award agreement. Awards that may become due under the Equity Uplift Component may be paid in the form of a single lump sum in cash or common units, at the discretion of the board of directors of our general partner.

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Certain payments may become due to MICP participants upon a “qualified termination” or a “change of control” (as those terms are defined in the MICP). For additional information, see “Potential Payments Upon Termination or Change of Control” below.

Other Compensation Arrangements

Chesapeake also provides compensation in the form of personal benefits and perquisites to the named executive officers. Most of the benefits that Chesapeake provides to the named executive officers are the same benefits that are provided to all employees or large groups of senior-level employees of Chesapeake, including health and welfare insurance benefits, 401(k) matching contributions (up to 15 percent of an employee’s annual base salary and cash incentive bonus compensation), nonqualified deferred compensation arrangements and financial planning services. Chesapeake does not have a pension plan or any other retirement plan other than the 401(k) and nonqualified deferred compensation plans.

Employment Agreements

Messrs. Stice, Shiels and Purgason have entered into employment agreements that govern the terms and conditions of their employment, including their duties and responsibilities, compensation and benefits, and applicable severance terms, which are described below under “Potential Payments Upon Termination or Change of Control.”

Agreement with J. Mike Stice

Mr. Stice’s employment agreement was amended and restated on November 10, 2011 and further amended December 22, 2011. His employment agreement has a three-year term expiring on November 10, 2014, unless terminated prior to such date by Chesapeake or Mr. Stice. Pursuant to the shared services agreement, the compensation expense allocated to us in 2011 with respect to Mr. Stice was 50 percent of his total compensation.

The agreement provides for Mr. Stice’s service as the Chief Executive Officer of our general partner with an annual base salary of $600,000. Mr. Stice was entitled to a guaranteed annual cash bonus for calendar year 2011 in the amount of $425,000. Mr. Stice also was entitled to receive at least $1,750,000 worth of Chesapeake restricted stock or Partnership phantom units for his service in 2011. Pursuant to his employment agreement, beginning in 2012 Mr. Stice no longer has guaranteed minimum salary, cash bonus or equity awards levels.

In 2011, Mr. Stice was granted cash and equity bonuses above his respective guaranteed minimum levels based on a subjective evaluation of the Partnership’s overall strong performance and his significant individual contributions to the Partnership’s and Chesapeake’s midstream achievements, including maintaining stable cash flows leading to distributions for 2011 equal to $1.48 per unit. We reimbursed Chesapeake for $263,000 related to the cash bonus Mr. Stice earned in 2011 and $931,867 related to equity awards Mr. Stice earned in 2011, consisting of 9,353 Partnership phantom units and 23,718 shares of Chesapeake restricted stock.

Agreements with David C. Shiels and Robert S. Purgason

The employment agreements with Messrs. Shiels and Purgason are effective January 4, 2010 and December 1, 2009, respectively. The employment agreements each have a five-year term. Mr. Shiels serves as our general partner’s Chief Financial Officer, and Mr. Purgason serves as our general partner’s Chief Operating Officer.

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The agreements provide Messrs. Shiels and Purgason with an annual base salary for 2011 of $325,000 and $375,000, respectively, which increased to $350,000 and $400,000, respectively, effective January 1, 2012. Additionally, the agreements specify target annual bonuses for Messrs. Shiels and Purgason in the following amounts, payable in cash: (i) $125,000 and $325,000, respectively, which were paid in full by January 31, 2012, and (ii) $150,000 and $350,000, respectively, payable not later than January 31, 2013, provided Messrs. Shiels and Purgason remain employed on the bonus dates. Payment of any bonus compensation is not guaranteed and remains within the discretion of Chesapeake. Additionally, discretionary bonuses above the target bonus amounts may be made, in cash and/or units, based on each executive’s annual performance review. The agreements further provide that Messrs. Shiels and Purgason are each eligible to receive awards under our MICP.

In 2011, Messrs. Shiels and Purgason were granted bonuses consisting of cash and equity awards above their respective target bonus levels based on a subjective evaluation of the Partnership’s overall strong performance and their significant individual contributions to the Partnership’s achievements, including maintaining stable cash flows leading to distributions for 2011 equal to $1.48 per unit. Mr. Shiels and Purgason earned a cash bonus of $151,000 and $352,500, respectively, and each earned 7,190 Partnership phantom units with a grant date value of $205,646. In addition, Messrs. Shiels and Purgason received their participation interest for the Excess Return Component of these MICP awards granted in 2010. Mr. Purgason’s compensation levels are greater than Mr. Shiels in recognition of Mr. Purgason’s broad-ranging responsibilities and extensive industry experience.

No amendments to the employment agreement with Messrs. Shiels and Purgason that would increase the compensation expenses reimbursable under the employee secondment agreement or adversely affect the protections afforded to us under the agreement may be made without the consent of the disinterested directors and the special committee of our general partner’s board of directors.

Compensation Changes for 2012

Due to Chesapeake’s continuing and rapid growth and, in an effort to pursue best practices, in early 2011 Chesapeake’s Compensation Committee retained an independent compensation consultant to review its current compensation system and provide recommendations to the Chesapeake’s Compensation Committee with respect to future improvements. On December 21, 2011, Chesapeake announced that following an extensive evaluation of its executive compensation, and with the advice of its independent compensation consultant, Cogent Compensation Partners, Chesapeake’s Compensation Committee and Chesapeake’s Board approved changes to Chesapeake executive compensation program. Mr. Stice will participate in the new executive compensation program in 2012. For more details regarding Chesapeake’s new executive compensation program please see “Executive Compensation” of Chesapeake’s proxy statement for its annual meeting of shareholders, which is expected to be filed no later than April 30, 2012.

Compensation Committee Report

The Compensation Committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth above. Based on the review and discussion, the Committee recommended to the board of directors of Chesapeake Midstream GP, L.L.C. that the Compensation Discussion and Analysis be included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2011.

Members of the Compensation Committee:

Suedeen G. Kelly, Chairman

Domenic J. Dell’Osso, Jr.

Matthew C. Harris

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Long-Term Incentive Plan

General

Our general partner has adopted the Chesapeake Midstream LTIP, for employees, consultants and directors of our general partner and its affiliates, including Chesapeake, who perform services for us. The summary of the LTIP contained herein does not purport to be complete and is qualified in its entirety by reference to the LTIP. The LTIP provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights with respect to phantom units, and other unit-based awards. Subject to adjustment for certain events, an aggregate of 3,500,000 common units may be delivered pursuant to awards under the LTIP. Units from awards that are cancelled or forfeited are available for delivery pursuant to other awards. The LTIP is administered by our general partner’s board of directors. The LTIP has been designed to promote the interests of the Partnership and its unitholders by strengthening the Partnership’s ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees.

Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture during the restricted period. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of our general partner, cash equal to the fair market value of a common unit. The board of directors of our general partner may make grants of restricted units and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the board may determine are appropriate, including the period over which restricted or phantom units will vest. Our general partner may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement. Upon the vesting of phantom units, common units equal to the number of phantom units then vesting, or cash equal to the fair market value thereof, is delivered to the grantee, less the number of units or amount of cash equal to the income taxes payable on the vesting of the phantom units.

Distributions made by us with respect to awards of phantom units may, in the discretion of the board of directors of our general partner, be subject to the same vesting requirements as the restricted units. Our general partner, in its discretion, may also grant tandem distribution equivalent rights with respect to phantom units. Distribution equivalent rights are rights to receive an amount equal to all or a portion of the cash distributions made on units during the period a phantom unit remains “outstanding.” Restricted units and phantom units granted under the LTIP serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants do not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner receives remuneration for the units delivered with respect to these awards.

The board of directors of our general partner has approved and intends to continue to approve annual phantom unit grants to each of Messrs. Daberko and Frederickson and Ms. Kelly on the first business day of each calendar year and annually thereafter while the director serves as a member of our general partner’s board having an aggregate value to each director of approximately $50,000. The actual number of phantom units awarded under this grant will be determined by dividing $50,000 by the closing unit price per unit on the date of grant. The phantom units will vest one quarter immediately and on each of the first, second and third anniversary of the grant date (with vesting to be accelerated upon the grantee’s death or disability or the change of control of our general partner). On January 3, 2012, each of Messrs. Daberko and Frederickson and Ms. Kelly was awarded 1,712 phantom units.

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Unit Options and Unit Appreciation Rights

The LTIP also permits the grant of options and unit appreciation rights covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units as determined by the board. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as our general partner may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price greater than or equal to the fair market value of a common unit on the date of grant.

Other Unit-Based Awards

The LTIP also permits the grant of other unit-based awards, which are awards that, in whole or in part, are valued or based on or related to the value of a unit. The vesting of any other unit-based award may be based on a participant’s length of service, the achievement of performance criteria or other measures. On vesting, any other unit-based award may be paid in cash and/or in units (including restricted units), as our general partner may determine.

Source of Common Units; Cost

Common units to be delivered with respect to awards may be newly issued units, common units acquired by our general partner in the open market, common units already owned by our general partner, Chesapeake or us, common units acquired by our general partner from any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring such common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash, our general partner will be entitled to reimbursement by us for the amount of the cash settlement. With respect to unit options and unit appreciation rights, our general partner will be entitled to reimbursement from us for the difference between the cost it incurs in acquiring these common units and the proceeds it receives from an optionee at the time of exercise of an option. Thus, we will bear the cost of the unit options.

Amendment or Termination of Long-Term Incentive Plan

The board of directors of our general partner, in its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the earlier of the 10th anniversary of the date it was initially adopted by our general partner or when common units are no longer available for delivery pursuant to awards under the LTIP. The board of directors of our general partner will also have the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP; provided, however, that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant, and/or result in taxation to the participant under Section 409A of the Internal Revenue Code (the “Code”).

Upon a change of control of us or our general partner, the board of directors of our general partner may, in its sole discretion:

• provide for either (A) the termination of any award in exchange for an amount of cash, if any, equal to the amount that would have been then attained upon the exercise or vesting of the award or (B) the replacement of the award with other rights or property;

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• provide that the award be assumed by the successor or survivor entity or be exchanged for similar awards of the equity of the successor or survivor, with appropriate adjustments;

• make adjustments in the number and type of common units subject to, and terms and conditions and any performance criteria of, the award;

• provide that the award will be exercisable or payable, notwithstanding anything to the contrary in the LTIP or the award agreement; and

• provide that the award will be terminated upon such event.

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Summary Compensation Table

The following table summarizes the compensation amounts for each of the named executive officers for the fiscal year ended December 31, 2011.

Name and Principal Position	Year		Salary ($)(1)		Bonus ($)(2)		Stock Awards ($)(3)		Option Awards ($)(3)		Non-Equity Incentive Plan Compen- sation ($)(4)		Change in Pension Value and Nonqualified Deferred Compen- sation Earnings ($)(5)		All Other Compen- sation ($)(6)		Total ($)
J. Mike Stice(7)     Chief Executive Officer		2011 2010	$	299,038 249,308	$	263,000 188,000	$	931,867 637,400	$	— —	$	— —	$	— —	$	154,284 13,263	$	1,648,189 1,087,971
David C. Shiels     Chief Financial Officer		2011 2010		329,606 300,337		151,000 225,500		205,646 —		— —		36,267 6,378		— —		267,718 46,451		990,237 578,666
Robert S. Purgason     Chief Operating Officer		2011 2010		374,760 356,106		352,500 301,300		205,646 —		— —		72,534 12,756		— —		109,507 81,776		1,114,947 751,938

(1) The amounts in this column reflect the base salary compensation earned by our named executive officers for the year indicated.

(2) The amounts in this column reflect bonuses earned by the named executive officers in the year indicated. For each of the named executive officers, the bonus amounts include bonuses provided for in their respective employment agreements and routine holiday bonuses.

(3) The amount shown in these columns reflect the aggregate grant date fair value of Chesapeake restricted stock awards granted to Mr. Stice and phantom unit awards granted to Messrs. Stice, Shiels and Purgason in the year indicated, determined in accordance with FASB ASC Topic 718. The value ultimately realized by the executives upon the actual vesting of the awards may or may not be equal to the grant date fair value. Refer to the Grants of Plan-Based Awards in 2011 table for additional information regarding restricted stock and phantom unit awards made to the named executive officers in the year ended December 31, 2011. More information about the named executive officers’ outstanding restricted stock and phantom units as of December 31, 2011 is provided in the Outstanding Equity Awards at Fiscal Year-End 2011 table. Unvested Chesapeake restricted stock does not accrue dividends. Unvested phantom units do accrue distributions which are paid out upon the vesting of such units. Distribution equivalent rights are not reflected in the aggregate grant date fair value of phantom unit awards.

(4) The amounts shown in this column reflect amounts earned from awards made in January 2010 pursuant to the Excess Return Component of the MICP. The amounts in this column will be paid pro-rata to the named executive officers over the remaining years of the MICP, subject to their continued employment with the partnership. The amounts for 2010 were revised to reflect the correction by the compensation committee of miscalculated awards for that year. See “Compensation Discussion and Analysis—Elements and Mix of Compensation—Management Incentive Compensation Plan” above for more information regarding the MICP.

(5) Our named executive officers do not participate in a pension plan, and Chesapeake’s nonqualified deferred compensation plans do not provide for above-market or preferential earnings. See “Nonqualified Deferred Compensation for 2011” below for information regarding Chesapeake’s nonqualified deferred compensation plan.

(6) The amounts in this column reflect all other compensation earned by the named executive officers for the fiscal year ended December 31, 2011. The other compensation provided to the named executive officers consists of matching contributions under Chesapeake’s 401(k) and nonqualified deferred compensation plans, distribution equivalent rights credited to the named executive officers, supplemental life insurance premiums and financial advisory services. In addition, this column reflects a relocation benefit of $196,950 and a commuting allowance provided to Mr. Shiels in the year ended December 31, 2011.

(7) The amounts for Mr. Stice reflect compensation for his time spent providing services to the Partnership in the year indicated, which, in each case, was approximately 50 percent of his time.

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Grants of Plan-Based Awards in 2011

The following table sets forth information concerning Chesapeake restricted stock and phantom units granted during 2011 to Mr. Stice in connection with his service to us, as well as phantom units granted to Messrs. Shiels and Purgason.

Name	Grant Date	Approval Date(1)	All Other Stock Awards: Number of Shares of Stock or Units (#)(2)		Grant Date Fair Value of Stock Awards ($)(3)
J. Mike Stice(4)	January 3, 2011	December 16, 2010		3,750	$	107,325
	January 3, 2011	January 1, 2011		13,750		364,513
	July 1, 2011	June 13, 2011		5,603		160,007
	July 1, 2011	July 1, 2011		9,968		300,022
						931,867
David C. Shiels(5)	January 3, 2011	December 16, 2010		5,000		143,100
	July 1, 2011	June 13, 2011		2,190		62,546
						205,646
Robert S. Purgason(5)	January 3, 2011	December 16, 2010		5,000		143,100
	July 1, 2011	June 13, 2011		2,190		62,546
						205,646

(1) Chesapeake approved the Chesapeake restricted stock awards to Mr. Stice in accordance with its regular procedures. Our general partner’s board of directors approved the phantom unit awards to the named executive officers at regularly scheduled meetings. Chesapeake’s and the general partner’s approval on January 1, 2011 and December 16, 2010, respectively, provided for the restricted stock and phantom unit grant dates to be the first trading day of January 2011. Chesapeake’s and the general partner’s approvals on July 1, 2011 and June 13, 2011, respectively, provided for the restricted stock and phantom unit grant dates to be the first trading day of July 2011.

(2) The restricted stock and phantom unit awards granted in 2011 vest ratably over four years from the grant date of the award. No dividends are accrued or paid on restricted stock awards until vested. Unvested phantom units accrue distributions that are paid out upon the vesting of such units.

(3) The amounts shown in this column represent the aggregate grant date fair value of the awards, determined in accordance with FASB ASC Topic 718. The values shown in reference to restricted stock awards are based on the closing price of Chesapeake’s common stock on the grant date. The values shown in reference to phantom unit awards are based on the closing price of the Partnership’s common units on the grant date. The value ultimately realized by the executive upon the actual vesting of the awards may or may not be equal to the grant date fair value. Unvested restricted stock does not accrue dividends. Unvested phantom units accrue distributions that are paid out upon the vesting of such units. Distribution equivalent rights are not reflected in the aggregate grant date fair value of phantom unit awards.

(4) Includes 23,718 shares of Chesapeake restricted stock and 9,353 phantom units granted to Mr. Stice in 2011.

(5) Messrs. Shiels and Purgason were granted only phantom units in 2011.

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Outstanding Equity Awards at Fiscal Year-End 2011

The following table reflects outstanding equity awards as of December 31, 2011 for each of the named executives, including both Chesapeake and Partnership awards granted in connection with their service to the Partnership.

	Stock Awards
	Grant Date of Shares or Units of Stock That Have Not Vested		Number of Shares or Units of Stock That Have Not Vested(#)(1)		Market Value of Shares or Units of Stock That Have Not Vested($)(2)
J. Mike Stice		January 4, 2010		9,375	$	208,969
		July 1, 2010		10,313		229,877
		January 3, 2011		3,750		108,750
		January 3, 2011		13,750		306,487
		July 1, 2011		9,968		222,187
		July 1, 2011		5,603		162,487
David C. Shiels		January 3, 2011		5,000		145,000
		July 1, 2011		2,190		63,510
Robert S. Purgason		January 3, 2011		5,000		145,000
		July 1, 2011		2,190		63,510

(1) By their terms, the Chesapeake restricted stock awards and phantom unit awards vest ratably over four years from the grant date of the award.

(2) The value shown for Chesapeake restricted stock awards is based on the closing price of Chesapeake’s common stock on December 30, 2011 of $22.29 per share. The value shown for phantom unit awards is based on the closing price of the Partnership’s common units on the NYSE on December 30, 2011 of $29.00 per unit.

Option Exercises and Stock Vested in 2011

The following table reflects Chesapeake restricted stock awards that vested in 2011. The dollar amounts and number of securities included in the table below reflect an allocation based upon the time allocation for Mr. Stice previously discussed.

	Stock Awards
Name	Number of Shares Acquired on Vesting (#)		Value Realized on Vesting ($)
J. Mike Stice(1)		6,563	$	184,207
David C. Shiels.		—		—
Robert S. Purgason		—		—

(1) The number of shares acquired on vesting reflects the vesting of Chesapeake restricted stock awards granted to him in connection with his service to the Partnership. The value realized on vesting is based on the closing price of Chesapeake’s common stock on the vesting dates.

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Nonqualified Deferred Compensation for 2011

Name	Executive Contribution in Last Fiscal Year ($)(1)		Registrant Contributions in Last Fiscal Year ($)(2)		Aggregate Earnings in Last Fiscal Year ($)			Aggregate Withdrawals/ Distributions ($)		Aggregate Balance at Last Fiscal Year-End ($)
J. Mike Stice	$	109,712	$	109,712	$	(21,172	)	$	—	$	198,252
David C. Shiels.		16,230		16,230		(1,643	)		—		30,817
Robert S. Purgason		58,964		58,964		(8,763	)		—		109,165

(1) Executive contributions are included as compensation in the Salary and Bonus columns, as applicable, of the Summary Compensation Table.

(2) Company matching contributions are included as compensation in the All Other Compensation column of the Summary Compensation Table.

The named executive officers are permitted to participate in the Chesapeake Amended and Restated Deferred Compensation Plan (the “DCP”), a nonqualified deferred compensation plan. The DCP allows certain employees to voluntarily defer receipt of a portion of their salary and/or their annual bonus payments. Pursuant to the terms of the employee secondment agreement and, in the case of Mr. Stice, the shared services agreement, a portion of the expense related to these plans is allocated to us by Chesapeake. For additional discussion of the DCP, please see “Executive Compensation—Nonqualified Deferred Compensation Table for 2011” of Chesapeake’s proxy statement for its annual meeting of shareholders, which is expected to be filed no later than April 30, 2012.

Potential Payments Upon Termination or Change of Control

As discussed under “Compensation Discussion and Analysis” above, Chesapeake has entered into employment agreements with each of the named executive officers that govern the terms and conditions of their employment, including their duties and responsibilities, compensation and benefits, and applicable severance terms. The energy industry’s history of terminating professionals during its cyclical downturns and the frequency of mergers, acquisitions and consolidation in our industry are two important factors that have contributed to a widespread, heightened concern for long-term job stability by many professionals in our industry. In response to this concern, arrangements that provide compensation guarantees in the event of an employee’s termination without cause, death or incapacity or due to a change of control are common practice in our industry. These provisions in the named executive officers’ employment agreements and the incentive plans in which the named executive officers participate are integral to our ability to recruit and retain the high caliber of professionals that are critical to the successful execution of our business strategy. Below is a discussion of these arrangements.

J. Mike Stice.   Mr. Stice’s employment agreement provides for certain change of control and termination benefits in the event of a change of control or a termination of Mr. Stice’s employment under certain circumstances. If a change of control (as defined below) occurs during the term of the agreement, Mr. Stice will receive a lump sum payment within 30 days of the effective date of the change of control, equal to 200 percent of the sum of Mr. Stice’s then-current annual base salary and the actual bonuses paid to Mr. Stice during the twelve-month period preceding the change of control. Additionally, all equity compensation granted under the employment agreement will vest in full.

Upon written notice, Mr. Stice’s employment may be terminated by either party to his agreement for any reason. Generally, upon any termination, Mr. Stice will be entitled to receive only accrued but unpaid compensation, such as paid time off (“PTO”) amounts, and any amounts due to him pursuant to the terms of an employee benefit plan. If Mr. Stice’s employment is terminated without cause (as defined below), he will also be entitled to receive a lump sum payment equal to 52 weeks of base salary and all equity compensation granted under the employment agreement as well as his supplemental matching contributions under the DCP will vest in full upon termination.

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In the event of Mr. Stice’s retirement following at least five years of service and the attainment of at least age 55, Mr. Stice will receive accelerated vesting, in whole or in part, of (i) his supplemental matching contributions under the DCP and (ii) all equity compensation granted under the employment agreement. If Mr. Stice dies, his beneficiary or estate will be entitled to (i) receive a lump sum payment equal to 52 weeks of base salary (reduced by any benefits payable under any disability plans provided by the Company), (ii) vesting in full of all equity compensation granted under the employment agreement as well as his supplemental matching contributions under the DCP and (iii) receive payment of any PTO amounts accrued through the termination date.

If Mr. Stice is terminated due to a disability (as defined below), he will be entitled to (i) receive a lump sum payment equal to 26 weeks of base salary (reduced by any benefits payable under any disability plans provided by the Company), (ii) vesting in full of all equity compensation granted under the employment agreement as well as his supplemental matching contributions under the DCP and (iii) receive payment of any PTO amounts accrued through the termination date.

All severance payments due upon Mr. Stice’s termination without cause or due to his disability will be made within 30 days of the termination date (90 days, in the case of death), unless Mr. Stice constitutes a “specified employee” within the meaning of Section 409A of the Code, in which case payments subject to Section 409A of the Code will be delayed for six months following the termination date. All severance payments and benefits are contingent on Mr. Stice (or, in the event of his death, his beneficiary or the administrator of his estate) executing (and not revoking) a severance and release agreement within 45 days of the termination, and complying with the restrictive covenants described below.

Mr. Stice’s agreement contains certain confidentiality, noncompete, and nonsolicitation covenants. Specifically, Mr. Stice has agreed not to disclose any confidential information during the term of his employment and for three years following his termination. In addition, Mr. Stice has agreed to a noncompete covenant for six months following his termination and not to solicit customers or employees for a period of one year following his termination.

A “change of control” is generally defined in Mr. Stice’s employment agreement as the occurrence of one of the following: (a) the acquisition by a group of 30 percent or more of the outstanding shares of Chesapeake common stock or the combined voting power of the then outstanding Chesapeake securities (other than acquisitions by or from Chesapeake, by a Chesapeake employee benefit plan, in a transaction sponsored by Aubrey K. McClendon, or by an entity described in the remaining subsections of this definition); (b) the individuals on the Chesapeake board of directors as of June 11, 2010, cease to constitute at least a majority of that board; (c) the consummation of a reorganization, merger, consolidation or sale of all or substantially all of the assets of Chesapeake; or (d) the approval by the Chesapeake shareholders of a complete liquidation or dissolution. “Cause” is defined in the agreement as Mr. Stice’s breach or threatened breach of his agreement, his neglect of or failure to perform his duties, his misappropriation, fraudulent conduct or dishonesty with respect to company business, or his personal misconduct which injures Chesapeake and/or reflects poorly on Chesapeake’s reputation. A termination without cause includes such events as Chesapeake’s elimination of Mr. Stice’s position, a material reduction in duties and/or reassignment of Mr. Stice to a new position of less authority, or a material reduction to his compensation. Mr. Stice will be considered incapacitated, or disabled, under his employment agreement if he suffers from a physical or mental condition which, in the reasonable judgment of Chesapeake’s management, prevents Mr. Stice from performing his duties for a period of at least three consecutive months.

Mr. Stice’s termination and change of control benefits are provided to him in connection with the services that he provides to Chesapeake, and the Partnership is not required to reimburse Chesapeake for any such benefits.

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David C. Shiels and Robert S. Purgason.  Mr. Shiels’ and Mr. Purgason’s employment agreements provide for certain termination benefits in the event of termination under certain specified circumstances. Upon written notice, Mr. Shiels’ or Mr. Purgason’s employment may be terminated by either party to the agreement for any reason. Generally, upon any termination, each of Messrs. Shiels and Purgason will be entitled to receive only accrued but unpaid compensation, such as base salary and vacation amounts, and any amounts due to him pursuant to the terms of an employee benefit plan.

If employment is terminated without cause (similarly defined as the term “cause” in Mr. Stice’s agreement described above), Mr. Purgason will be entitled to a lump sum payment equal to one year’s worth of base salary and Mr. Shiels will be entitled to a lump sum payment equal to 26 weeks of base salary. If the termination without cause occurs within two years following the occurrence of a change of control (as defined in the employment agreement), each of Messrs. Shiels and Purgason is also entitled to receive, in addition to the base salary amounts described in the preceding sentence, an amount equal to the actual bonuses paid to him during the 12 calendar months preceding the change of control.

If either Mr. Shiels or Mr. Purgason is terminated due to a disability (similarly defined as the terms “incapacitated” and “disabled” in Mr. Stice’s agreement described above), he will be entitled to a lump sum payment equal to 26 weeks of base salary, reduced by any benefits payable under any employer-sponsored disability plan. If either Mr. Shiels or Mr. Purgason dies, his beneficiary or estate will be entitled to receive a lump sum payment equal to 52 weeks of his base salary.

All severance payments due upon the termination of Messrs. Shiels and Purgason will be made within 30 days of the termination date (90 days, in the case of death), unless the executive constitutes a “specified employee” within the meaning of Section 409A of the Code, in which case payments subject to Section 409A will be delayed until the earlier of the executive’s death or six months following the termination date. Such payments are contingent on the executive (or, in the event of his death, his beneficiary or the administrator of his estate) executing (and not revoking) a severance and release agreement within 30 days of the termination (90 days, in the case of death), and complying with the restrictive covenants described below.

The employment agreements with Messrs. Shiels and Purgason contain certain confidentiality, noncompete, and nonsolicitation covenants. Specifically, each of Messrs. Shiels and Purgason has agreed not to disclose any confidential information at any time either during or following the term of his employment. In addition, Messrs. Shiels and Purgason have agreed to a noncompete covenant for 26 weeks and one year, respectively, following termination and not to solicit customers or employees for a period of one year following termination. Termination of either Mr. Shiels’ or Mr. Purgason’s employment due to the violation of one of these covenants would constitute a termination for cause.

Messrs. Shiels and Purgason are participants under the MICP. Under the MICP, unless waived by the compensation committee of the board of directors of our general partner, in its discretion, if a participant’s employment terminates for any reason prior to a payment date, other than due to his death, disability, involuntary termination by the employer other than for “cause” (as defined in the MICP), or by the participant for a “good reason” (as defined in the MICP) (such events collectively being a “Qualified Termination”), the participant’s award will be automatically forfeited on his or her termination of employment. If, however, a participant’s termination of employment is a Qualified Termination, the participant will be paid (i) on his termination the remaining amount of any unpaid annual installments attributable to the participant’s Excess Return Component for the fiscal years that have been completed as of the participant’s termination date, and (ii) at the end of the five-year period, a pro rata portion of the participant’s Equity Uplift Component (if any) during such five-year period. Awards will be paid in cash, unless the board of directors of our general partner otherwise elects, in its discretion, to pay all or part of the Equity Uplift Component of the award in our common units.

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Upon a change of control (as defined in the MICP), a participant who is an employee immediately prior to the change of control will be paid (i) with respect to the Excess Return Component, the remaining amount of unpaid installments attributable to fiscal years then completed and (ii) with respect to the Equity Uplift Component, an amount based on the increase in the value of our common units over the beginning value of our common units. A participant who has incurred a Qualified Termination prior to the change of control will receive, with respect to the Equity Uplift Component, a pro rata portion of the amount that otherwise would have been payable to him had his employment continued until the change of control. The MICP will terminate on a change of control.

The tables below provide estimates of the compensation and benefits that would have been payable to Messrs. Shiels and Purgason under each the above described arrangements if such termination events had been triggered as of December 31, 2011.

David C. Shiels - Executive Benefits and Payments Upon Separation	Termination without Cause		Change of Control		Retirement		Incapacity of Executive		Death of Executive
Compensation:
Cash Severance	$	167,500	$	283,500	$	—	$	167,500	$	335,000
Acceleration of Equity Compensation:
Phantom Unit Awards(1)		—		208,510		—		—		—
401(k)/Deferred Comp Plan Matching		—		14,645		—		22,424		22,424
Acceleration of Non-Equity Incentive Compensation:
Management Incentive Compensation Plan(2)		441,214		1,039,068		—		441,214		441,214
Benefits and Perquisites:
Accrued Vacation Pay		282		282		282		282		282
Total	$	608,996	$	1,546,005	$	282	$	631,420	$	798,920

(1) Amounts based on the closing price of the partnership’s common units on December 31, 2011.

(2) Includes acceleration of both Excess Return Component and Equity Uplift Component. Estimated amounts that would have been payable under the Equity Uplift Component, on December 31, 2011, based upon the assumption that the Partnership’s common units would be valued at $26.77, the average closing price for the units over a trailing 30-day period.

Robert S. Purgason - Executive Benefits and Payments Upon Separation	Termination without Cause		Change of Control		Retirement		Incapacity of Executive		Death of Executive
Compensation:
Cash Severance	$	375,000	$	692,500	$	—	$	187,500	$	375,000
Acceleration of Equity Compensation:
Phantom Unit Awards(1)		—		208,510		—		—		—
401(k)/Deferred Comp Plan Matching		—		52,337		—		20,083		20,083
Acceleration of Non-Equity Incentive Compensation:
Management Incentive Compensation Plan(2)		882,428		2,078,136		—		882,428		882,428
Benefits and Perquisites:
Accrued Vacation Pay		26,554		26,554		26,554		26,554		26,554
Total	$	1,283,982	$	3,058,037	$	26,554	$	1,116,566	$	1,304,066

(1) Amounts based on the closing price of the partnership’s common units on December 31, 2011.

(2) Includes acceleration of both Excess Return Component and Equity Uplift Component. Estimated amounts that would have been payable under the Equity Uplift Component, on December 31, 2011, based upon the assumption that the Partnership’s common units would be valued at $26.77, the average closing price for the units over a trailing 30-day period.

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Compensation of Directors

Officers or employees of Chesapeake and GIP who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Our independent directors receive compensation for their service on our general partner’s board of directors, which compensation was amended in July 2011. Such compensation now consists of an annual retainer of $80,000 for each board member, except for the chairman of the board of directors who receives $100,000. The independent directors also receive an initial grant of the number of units having a grant date value of approximately $50,000 upon initial appointment as a director of our general partner. The independent directors also receive an annual grant, effective on the first business day of January of each year that they serve as a director, of the number of units having a grant date value of approximately $50,000, 25 percent of which will vest on the grant date and 75 percent of which will be phantom units that vest one-third on each of the first, second and third anniversary of the date of grant (with vesting to be accelerated upon death, disability or a change of control of our general partner). In addition, each director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified by us, pursuant to individual indemnification agreements and our partnership agreement, for actions associated with being a director to the fullest extent permitted under Delaware law.

The following table sets forth the compensation earned by the directors of our general partner in 2011:

Name	Fees Earned or Paid in Cash ($)		Stock Awards ($)(1)		Option Awards ($)		All Other Compensation ($)(2)		Total ($)
David A. Daberko	$	89,310	$	50,028	$	—	$	1,868	$	141,206
Domenic J. (“Nick”) Dell’Osso(3)		—		—		—		—		—
Philip A. Frederickson		75,207		50,028		—		1,868		127,103
Suedeen G. Kelly		75,207		50,028		—		1,868		127,103
Matthew C. Harris		—		—		—		—		—
Aubrey K. McClendon		—		—		—		—		—
Marcus C. Rowland(3)		—		—		—		—		—
William A. Woodburn.		—		—		—		—		—

(1) Reflects the aggregate grant date fair value of 2011 unit awards computed in accordance with FASB ASC Topic 718. Messrs. Daberko and Frederickson and Ms. Kelly were each awarded 1,712 common units on January 3, 2012, 428 of which were immediately vested and the remainder of which were phantom units that vest one-third on each of the first, second and third anniversary of the date of grant. As of December 31, 2011, each of Messrs. Daberko and Frederickson and Ms. Kelly held 1,311 unvested phantom units.

(2) The amounts shown in this column reflect distribution equivalent rights with regard to phantom unit awards that were accrued and credited to the directors in 2011.

(3) Mr. Rowland resigned effective June 1, 2011 and Mr. Dell’Osso became a director on such date.

Compensation Committee Interlocks and Insider Participation

In 2011, Ms. Kelly and Messrs. Harris, Rowland and Dell’Osso served on the compensation committee of our general partner’s board of directors. Mr. Rowland was an executive officer of Chesapeake during 2010 and retired from that position in October 2010. Mr. Dell’Osso is an executive officer of Chesapeake and replaced Mr. Rowland as a director of our general partner effective June 1, 2011. Messrs. Rowland and Dell’Osso did not receive compensation in 2011 for service as a director of our general partner. Please see “Item 13. Certain Relationships and Related Transactions, and Director Independence” for more information about relationships among us, our general partner and Chesapeake.

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Relation of Compensation Policies and Practices to Risk Management

We expect our compensation arrangements to contain a number of design elements that serve to minimize the incentive for taking excessive or inappropriate risk to achieve short-term, unsustainable results. In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us. Please read “—Compensation Discussion and Analysis.”

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth the beneficial ownership of our units that, unless otherwise noted, as of February 22, 2012, are held by:

• each member of our general partner’s board of directors;

• each named executive officer of our general partner;

• all directors and officers of our general partner as a group; and

• each person or group of persons known by us to be a beneficial owner of 5 percent or more of the then outstanding units.

Name and address of beneficial owner(1)	Common units beneficially owned		Percentage of common units beneficially owned(2)			Subordinated units beneficially owned		Percentage of subordinated units beneficially owned(2)			Percentage of total common and subordinated units beneficially owned(2)
Chesapeake Energy Corporation(3)		33,704,666		42.7	%		34,538,061		50.0	%		46.1	%
GIP(5) 12 E. 49th Street, 38th Floor New York, NY 10017		—		—			34,538,061		50.0	%		23.3	%
Tortoise Capital Advisors, LLC(4) 11550 Ash Street, Suite 300 Leawood, Kansas 66211		6,045,516		8.8	%		—		—			4.1	%
J. Mike Stice		13,614		*	%		—		—			*	%
Robert S. Purgason		15,001		*	%		—		—			*	%
David C. Shiels		801		*	%		—		—			*	%
Matthew C. Harris(5)		—		*	%		—		—			*	%
Aubrey K. McClendon(3)(6)		53,700		*	%		—		—			*	%
Domenic J. (“Nick”) Dell’Osso		6,000		*	%		—		—			*	%
William A. Woodburn(5)		—		*	%		—		—			*	%
David A. Daberko		8,383		*	%		—		—			*	%
Philip L. Frederickson		13,183		*	%		—		—			*	%
Suedeen G. Kelly		3,683		*	%		—		—			*	%
All directors and executive officers as a group (ten persons)		114,365		*	%		—		—			*	%

* Less than 1.0 percent

(1) Unless otherwise indicated, the address for all beneficial owners in this table is 900 N.W. 63rd Street, Oklahoma City, Oklahoma 73118.

(2) Based on 78,899,650 common units and 69,076,122 subordinated units outstanding.

(3) This information is as of January 9, 2012, as reported in a Schedule 13D filed by Chesapeake, the ultimate parent company of Chesapeake Midstream Holdings, who is the owner of 50 percent of the membership interests of Chesapeake Midstream Ventures and the owner of common units and subordinated units. Chesapeake may be deemed to beneficially own the interests held directly or indirectly by Chesapeake Midstream Holdings.

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(4) This information is as of December 31, 2011, as reported in a Schedule 13G filed by Tortoise Capital Advisors, L.L.C., an investment adviser to certain investment companies registered under the Investment Company Act of 1940, on February 10, 2012. The Schedule 13G reports (i) shared power to vote or direct the vote of 5,537,399 common units and (ii) shared power to dispose or direct the disposition of 6,045,516 common units. Tortoise Capital Advisors, L.L.C. may be deemed the beneficial owner of the securities covered by the Schedule 13G. Tortoise Capital Advisors, L.L.C. disclaims any beneficial interest in the securities reported on Schedule 13G.

(5) This information is as of February 7, 2012, as reported in a Schedule 13G filed jointly by Global Infrastructure Investors, Limited (“Global Infrastructure Investors”), Global Infrastructure Management, LLC (“Global Infrastructure Management”), Global Infrastructure GP, L.P., GIP-A Holding (CHK), L.P. (“GIP-A”), GIP-B Holding (CHK), L.P. (“GIP-B”) and GIP-C Holding (CHK), L.P. (“GIP-C”) on February 10, 2012 and as provided to us by Global Infrastructure Management. Global Infrastructure Investors is the sole general partner of Global Infrastructure GP, L.P., which is the sole general partner of the limited partnerships (the “GIP Partnerships”) that directly or indirectly own the general partners of each of GIP-A, GIP-B and GIP-C. Global Infrastructure Management manages the GIP Partnerships. GIP-A, GIP-B and GIP-C hold the following interests in us:

• GIP-A owns 12,455,939 subordinated units and a 18.0 percent membership interest in Chesapeake Midstream Ventures;

• GIP-B owns 4,400,496 subordinated units and a 6.4 percent membership interest in Chesapeake Midstream Ventures; and

• GIP-C owns 17,681,626 subordinated units and a 25.6 percent membership interest in Chesapeake Midstream Ventures.

Matthew C. Harris and William A. Woodburn, two of the directors of our general partner, as members of Global Infrastructure Management’s internal committees, are entitled to vote on decisions to vote, or to direct to vote, and to dispose, or to direct the disposition of, the common units and subordinated units held by GIP-A, GIP-B and GIP-C but cannot individually or together control the outcome of such decisions. Global Infrastructure Investors, Matthew C. Harris and William A. Woodburn disclaim beneficial ownership of the common units and subordinated units held by GIP-A, GIP-B and GIP-C in excess of their respective pecuniary interest in such units. Global Infrastructure Investors and Global Infrastructure Management disclaim beneficial ownership of the common and subordinated units held by GIP-A, GIP-B and GIP-C.

(6) Includes 47,600 common units held by Mr. McClendon’s immediate family members sharing the same household.

The following table sets forth the number of shares of common stock of Chesapeake that, as of February 22, 2012, are owned by each of the executive officers, directors and nominees to our general partner’s board of directors and all directors and executive officers of our general partner as a group.

Name and address of beneficial owner(1)	Shares of common stock owned directly or indirectly		Shares underlying options exercisable within 60 days		Total shares of common stock beneficially owned		Percentage of total shares of common stock beneficially owned(2)
J. Mike Stice		60,141		—		60,141		*	%
Robert S. Purgason		1,269		—		1,269		*	%
David C. Shiels		1,007		—		1,007		*	%
Matthew C. Harris		—		—		—		*	%
Aubrey K. McClendon		1,774,883		—		1,774,883		*	%
Domenic J. (“Nick”) Dell’Osso, Jr.		62,749		—		62,749		*	%
William A. Woodburn		—		—		—		*	%
David A. Daberko		1,000		—		1,000		*	%
Philip L. Frederickson		—		—		—		*	%
Suedeen G. Kelly		—		—		—		*	%

* Less than 1.0 percent

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(1) The address for all beneficial owners in this table is 900 N.W. 63rd Street, Oklahoma City, Oklahoma 73118.

(2) As of February 22, 2012, there were 662,498,825 shares of Chesapeake common stock issued and outstanding.

Securities authorized for issuance under equity compensation plan

The following table sets forth information with respect to the securities that may be issued under the LTIP as of December 31, 2011. For more information regarding the LTIP, which did not require approval by our unitholders, please see “Item 11. Executive Compensation—Long-Term Incentive Plan.”

Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(1))
Equity compensation plans approved by security holders		—		—		—
Equity compensation plans not approved by security holders(1)		—		—		3,217,826

(1) The board of directors of our general partner adopted the LTIP in connection with our IPO.

ITEM 13. Certain Relationships and Related Transactions, and Director Independence

At February 22, 2012, Chesapeake owned 33,704,666 common units and 34,538,061 subordinated units, representing an aggregate 45.2 percent limited partner interest in us, and GIP owned 34,538,061 subordinated units, representing 22.9 percent limited partner interest in us. In addition, Chesapeake and GIP, through their joint ownership of Chesapeake Midstream Ventures, each indirectly own 50 percent of our general partner, which owns a 2.0 percent general partner interest in us and all of our incentive distribution rights.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and any liquidation of Chesapeake Midstream Partners, L.P. These distributions and payments were determined by and among affiliated entities.

Formation Stage

The aggregate consideration received by Chesapeake and GIP for the contribution of the assets and liabilities to us in connection with our IPO in 2010 •    47,826,122 common units; •    69,076,122 subordinated units; •    a 2.0 percent general partner interest; •    our incentive distribution rights; and •    GIP’s receipt of the net proceeds from the exercise of the underwriters’ option to purchase additional common units in connection with our initial public offering in 2010.

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Operational Stage

Distributions of available cash to our general partner and its affiliates

We generally make cash distributions 98.0 percent to our unitholders pro rata, including Chesapeake and GIP as the holders of an aggregate 33,704,666 common units and 69,076,122 subordinated units, and 2.0 percent to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0 percent interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner is entitled to increasing percentages of the distributions, up to 50.0 percent of the distributions above the highest target distribution level. If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and to maintain its general partner interest.

Payments to our general partner and its affiliates

Our general partner does not receive a management fee or other compensation for the management of our partnership. Prior to making distributions, we reimburse Chesapeake for its provision of certain general and administrative services and any additional services we may request from Chesapeake (including certain incremental costs and expenses we incur as a result of being a publicly traded partnership which are approximately $2.0 million per year), each pursuant to the services agreement; the costs and expenses of employees seconded to us pursuant to the employee secondment agreement; and certain costs and expenses incurred in connection with the services of Mr. Stice as the chief executive officer of our general partner pursuant to the shared services agreement. Other than the volumetric cap on general and administrative expenses included in the services agreement, our reimbursement obligations are uncapped. Please read “—Agreements with Affiliates—Services Agreement,” “—Employee Secondment Agreement” and “—Shared Services Agreement” below. In addition, we reimburse our general partner and its affiliates for all expenses they incur on our behalf. Under our partnership agreement, our general partner determines in good faith the amount of these expenses.

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Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
Liquidation	Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements with Affiliates

We have entered into the various documents and agreements with Chesapeake and certain of its affiliates, as described in more detail below. Substantially all of the commercial terms of these agreements were negotiated between Chesapeake and GIP in connection with their formation of the midstream joint venture Chesapeake Midstream Partners, L.L.C. In connection with our initial public offering in 2010, the commercial terms of these agreements were incorporated into amended agreements that were generally intended to provide us with substantially similar benefits and obligations of the private midstream joint venture.

Omnibus Agreement

We have entered into an omnibus agreement with Chesapeake Midstream Ventures and Chesapeake Midstream Holdings that will address the following matters:

• Chesapeake’s obligation to provide us with certain rights relating to certain future midstream business opportunities; and

• our right to indemnification for certain liabilities and our obligation to indemnify Chesapeake Midstream Ventures and affiliated parties for certain liabilities.

Business Opportunities.   Pursuant to the omnibus agreement, Chesapeake Midstream Holdings provides us, or causes Chesapeake and its affiliates to provide us, with the opportunity to make offers with respect to three specified categories of transactions as described in more detail below: (i) proximate area opportunities, (ii) terminating third-party contract opportunities and (iii) monetization transaction opportunities. The consummation, if any, and timing of any such future transactions will depend upon, among other things, our ability to reach an agreement with the applicable Chesapeake entity and our ability to obtain financing on acceptable terms. Although we have certain rights with respect to the potential business opportunities described below, we are not under any contractual obligation to pursue any such transactions and Chesapeake is under no obligation to accept any offer made by us with respect to such opportunities.

Proximate Area Opportunities.   Chesapeake Midstream Holdings is required to offer us the opportunity to make a first offer with respect to all potential investments in, opportunities to develop or acquisitions of any midstream energy projects (including well connections) within five miles of any of our Barnett or Mid-Continent acreage dedications that may from time to time become available to Chesapeake and its affiliates, other than those which were or will be subject to a certain agreed-upon dedication or similar arrangement, although Chesapeake will not be obligated to accept any offer we make. Our Barnett acreage dedication consists of portions of nine counties in northern Texas, including

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Johnson and Tarrant counties. Our Mid-Continent acreage dedication consists of portions Arkansas, Kansas, New Mexico, Oklahoma and Texas. We refer to the five mile areas outside of the acreage dedications as the “proximate areas”.

Upon our receipt of written notice of a proximate area opportunity, we have the right, exercisable within either ten days (in the case of individual well connections) or 30 days (in the case of all other proximate area opportunities), to make a first offer for us to pursue such opportunity. Such offer must include, to the extent reasonably practicable, reasonable detail regarding the terms upon which we would be willing to pursue such proximate area opportunity. Unless Chesapeake Midstream Holdings rejects our offer by written notice to us within 30 days of the delivery of our offer, our offer is be deemed to have been accepted by Chesapeake Midstream Holdings, and we have the right to pursue such proximate area opportunity on the terms set forth in our offer. In the event that we decline to make an offer or Chesapeake Midstream Holdings validly rejects our offer, Chesapeake will be free to pursue the proximate area opportunity on its own or in a transaction with an unaffiliated third party, provided that the terms and conditions of any such transaction cannot be more favorable in the aggregate to such participants or to such unaffiliated third party than as are set forth in our offer.

Terminating Third-Party Contract Opportunities. To the extent Chesapeake or any of its affiliates is a party to any material gas gathering agreement or other material midstream energy services agreement with any third party covering services provided within an acreage dedication or any proximate area and such agreement becomes terminable by the applicable Chesapeake entity at no cost and without liability or is otherwise terminated, our omnibus agreement requires the applicable Chesapeake entity to provide us notice of such terminating third-party contract. Upon receipt of notice of such a terminating third-party contract, we have the right, exercisable within 60 days, to make an offer stating the terms pursuant to which we would be willing to provide the services provided by such contract. Unless Chesapeake Midstream Holdings rejects our offer by written notice to us within 60 days of the delivery of our offer, our offer will be deemed to have been accepted by Chesapeake Midstream Holdings, and the applicable Chesapeake entity will enter into an agreement with us for the provision of the services covered by our offer on the terms set forth therein. In the event that Chesapeake Midstream Holdings validly rejects the offer, it is free to obtain the services covered by such terminating third-party contract from a third party, provided that such services are provided on terms and conditions no more favorable in the aggregate to such third party than as are set forth in our offer.

Monetization Transaction Opportunities. In the event that Chesapeake or any of its affiliates proposes to enter into any sale, transfer, disposition, joint venture or other monetization (whether involving assets or equity interests) of any midstream gathering systems and associated infrastructure assets located outside of the acreage dedications and the proximate areas, subject to certain exceptions, the applicable Chesapeake entity is required to first provide us with notice of such monetization transaction opportunity. Such notice must include any material terms, conditions and details (other than those relating to price, gas gathering and other commercial agreements to the extent not provided to any other third party in connection with the proposed transaction) as would be necessary for us to make a responsive offer to enter into the contemplated monetization transaction, which terms, conditions and details must at a minimum include any terms, conditions and details provided to third parties in connection with the proposed monetization transaction. Upon receipt of such notice, we have the right, exercisable within 60 days, to make an offer to the applicable Chesapeake entity to enter into the monetization transaction. Unless the applicable Chesapeake entity rejects our offer by written notice to us within 60 days of the delivery of our offer, our offer is deemed to have been accepted, and the applicable Chesapeake entity must enter into an agreement with us providing for the consummation of the monetization transaction on the terms set forth in our offer. If we do not make a valid offer in response to any such monetization opportunity, Chesapeake will be free to enter into such monetization opportunity with any third party on terms and conditions no more

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favorable to such third party than those set forth in the notice of such opportunity provided to us. In the event that the applicable Chesapeake entity validly rejects our offer, it is free to enter into the monetization transaction with a third party, provided that (i) the terms and conditions of the transaction (including those relating to gas gathering and other commercial agreements, but excluding those relating to price) cannot be more favorable in the aggregate to such third party than as are set forth in our offer and (ii) such monetization transaction is at a price equal to no less than 95 percent of the price set forth in our offer. Notwithstanding the foregoing, Chesapeake and its affiliates will not be required to provide us with a right of first offer with respect to the following types of transactions:

• equity financing transactions by Chesapeake in respect of any midstream gathering systems and/or associated infrastructure located outside of the acreage dedications and the proximate areas, the net proceeds of which are used to finance the construction, development and/or operation of such midstream gathering systems and/or associated infrastructure assets;

• any financing transactions consisting of debt that is non-convertible and non-exchangeable, provided that any such transaction or series of related transactions may include the issuance of equity interests to the parties providing financing or affiliates thereof that in the aggregate constitute less than 20 percent of the aggregate value of such financing transaction;

• any transactions that would result in a change of control of Chesapeake or a sale of all or substantially all of the assets of Chesapeake and its subsidiaries, taken as a whole;

• any sale, joint venture or other monetization of any midstream gathering system and/or associated infrastructure assets outside the acreage dedications and the proximate areas in connection with a sale of interests in oil and gas properties (including, but not limited to, volumetric production payments) in which the majority of the assets (by value) are comprised of oil and gas exploration and production assets;

• any transaction that was subject to a right of first refusal, purchase or similar commitment to a third party as of September 30, 2009;

• any exchange, swap or similar property-for-property transaction involving the exchange of any midstream gathering system and/or associated infrastructure assets outside the acreage dedications and the proximate areas for other midstream gathering systems and/or associated infrastructure assets outside the acreage dedications and the proximate areas, to the extent any net cash proceeds to Chesapeake from any such

• transaction or series of related transactions does not comprise more than 20 percent of the aggregate value of the assets subject to such transaction or series of related transactions; and

• any sale, transfer or disposition to a 100 percent affiliate of Chesapeake that remains a 100 percent affiliate of Chesapeake at all times following such sale, transfer or disposition.

Chesapeake’s obligations to provide us with the business opportunities outlined above may be terminated by Chesapeake at any time each of GIP and Chesapeake holds less than half of the ownership interest it held in Chesapeake Midstream Ventures as of the closing of this offering.

Indemnification.   Pursuant to the omnibus agreement, we are entitled to indemnification for certain liabilities, and we are required to indemnify Chesapeake Midstream Ventures for certain liabilities.

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Chesapeake Midstream Ventures’ indemnification obligations to us include the following:

• Environmental.   For a period of three years following the closing of our initial public offering in August 2010, Chesapeake Midstream Ventures is obligated to indemnify us for environmental losses by reason of, or arising out of, any violation, event, circumstance, action, omission or condition associated with the operation of our assets prior to the closing of the initial public offering, including: (i) any violation of or cost to correct a violation of any environmental laws, (ii) any environmental activity to address a release of hazardous substances and (iii) the release of, or exposure of any person to, any hazardous substance; provided, however, that (x) the aggregate liability of Chesapeake Midstream Ventures for environmental losses shall not exceed $15.0 million in the aggregate and (y) Chesapeake Midstream Ventures is only liable to provide indemnification for environmental losses to the extent that the aggregate dollar amount of losses suffered by us exceed $250,000. In no event does Chesapeake Midstream Ventures have any indemnification obligations under the omnibus agreement for any claim made as a result of additions to or modifications of current environmental laws enacted after the effective date of the omnibus agreement.

• Title.  For a period of three years after the closing of the initial public offering, Chesapeake Midstream Ventures will indemnify us for losses relating to our failure to be the owner as of the closing of the IPO of valid and indefeasible easement rights, leasehold and/or fee ownership interests in and to the lands on which our assets are located, and such failure renders us liable to a third party or unable to use or operate our assets in substantially the same manner that our assets were used and operated immediately prior to the closing of this offering.

• Governmental consents and permits. For a period of three years following the closing of our initial public offering in August 2010, Chesapeake Midstream Ventures is obligated to indemnify us for losses relating to our failure to have any consent or governmental permit necessary to allow (i) the transfer of any of our assets to us upon in connection with our initial public offering or (ii) any of our assets to cross the roads, waterways, railroads and other areas upon which any our assets are located as of the closing of our initial public offering, and any such failure specified in such clause (ii) renders us unable to use or operate our assets in substantially the same manner that our assets were used and operated immediately prior to our initial public offering.

• Taxes. Until the first day after the expiration of any applicable statute of limitations, Chesapeake Midstream Ventures is obligated to indemnify us for losses in respect of or arising from all federal, state and local income tax liabilities attributable to the ownership or operation of our assets prior to the closing of our initial public offering in August 2010.

In no event will Chesapeake Midstream Ventures be obligated to indemnify us for any claims, losses or expenses or income taxes referred to above to the extent such claims, losses or expenses or income taxes were either (i) reserved for in our financial statements as of the effective date of the omnibus agreement or (ii) are recovered under available insurance coverage, from contractual rights or other recoveries against any third party. Under the omnibus agreement, we agree to use commercially reasonable efforts to realize any applicable insurance proceeds and amounts recoverable under such contractual obligations.

We have agreed to indemnify Chesapeake Midstream Ventures, and the officers, directors, employees, agents and representatives of Chesapeake Midstream Ventures from and against all losses to the extent that such losses are in respect of or arise from events and conditions associated with the operation of our assets and occurring on or after the closing of our initial public offering in 2010, unless in any such case indemnification is of a type that would not be permitted under our partnership agreement.

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Services Agreement

We, our general partner, Chesapeake MLP Operating, L.L.C. and certain affiliates of Chesapeake have entered into an amended and restated services agreement that requires Chesapeake to provide general and administrative services and additional services to us in return for a reimbursement of certain of its expenses in connection therewith.

The table below sets forth the amount of general and administrative expenses for which we were obligated to reimburse Chesapeake pursuant to the services agreement for the year ended December 31, 2011.

	December 31, 2011
	(In millions)
Reimbursement for general and administrative services (including a portion of certain incremental costs and expenses we incurred as a result of being a publicly traded partnership, which were approximately $2.0 million in 2011)	$	23.7

General and Administrative Services and Reimbursement.  Under the services agreement, Chesapeake performs centralized corporate functions for us, including human resources, information technology, treasury, risk management, legal, executive management, security, environmental, regulatory, production control, supervisory control and data application systems, gas measurement, internal audit, accounting, legal services, certain investor relations functions, volume control, contract management support and other required corporate services and functions requested by us. In return for such general and administrative services, our general partner has agreed to reimburse Chesapeake, based on agreed upon formulas pursuant to the services agreement, on a monthly basis for the time and materials actually spent in performing general and administrative services on our behalf. Our reimbursement to Chesapeake of such general and administrative expenses in any given month is subject to a cap in an amount equal to $0.03065 per Mcf multiplied by the volume (measured in Mcf) of natural gas that we gather, transport or process, subject to an annual escalation. The $0.03065 per Mcf cap is subject to an annual upward adjustment each year as of October 1 equal to 50 percent of any increase in the Consumer Price Index and, subject to receipt of requisite approvals, such cap may be further adjusted to reflect changes in the general and administrative services provided by Chesapeake relating to new laws or accounting rules that are implemented.

The cap contained in the services agreement does not apply to the additional services reimbursement described below. Additionally, the cap does not apply to our direct general and administrative expenses and may not apply to certain of the incremental general and administrative expenses that we incur as a result of becoming a publicly traded partnership.

Additional Services and Reimbursement.  Chesapeake has agreed to provide us with certain additional services, at our request, under the services agreement, including engineering, construction, procurement, business analysis, commercial, cartographic and other similar services to the extent they are not already provided by the seconded employees. In return for such additional services, our general partner has agreed to reimburse Chesapeake on a monthly basis an amount equal to the time and materials actually spent in performing the additional services. The reimbursement for additional services is not subject to the general and administrative services reimbursement cap.

Chesapeake has agreed to perform all services under the relevant provisions of the services agreement using at least the same level of care, quality, timeliness and skill as it does for itself and its affiliates and with no less than the same degree of care, quality, timeliness and skill as its past practice in performing the services for itself and our business during the one year period prior to September 30, 2009. In any event, Chesapeake has agreed to perform such services using no less than a reasonable level of care in accordance with industry standards.

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In connection with the services arrangement, we have agreed to reimburse GIP for certain costs incurred by GIP in connection with assisting us in the operation of our business. For the twelve months ending December 31, 2011, we reimbursed GIP approximately $0.6 million for these support services.

The term of the services agreement will extend for additional twelve-month periods unless any party provides 180 days’ prior written notice otherwise prior to the expiration of the applicable twelve-month period ending on December 31.

Indemnification.  Pursuant to the services agreement, certain affiliates of Chesapeake (the “Chesapeake Affiliates”) have agreed to indemnify our general partner and its subsidiaries, Chesapeake MLP Operating, L.L.C. and us (collectively, the “Partnership Group”) from and against certain potential claims, losses and expenses attributable to (i) breaches by the Chesapeake Affiliates of the services agreement, (ii) acts or omissions by the Chesapeake Affiliates in providing services in breach of the standard of performance set forth in the services agreement and (iii) claims by a third party relating to (A) breaches by the Chesapeake Affiliates of the services agreement, or (B) the Chesapeake Affiliates’ gross negligence or willful misconduct.

Additionally, the Partnership Group has agreed to indemnify the Chesapeake Affiliates from and against certain potential claims, losses and expenses attributable to (i) breaches by the Partnership Group of the services agreement or (ii) claims by a third party relating to (A) any acts or omissions of the Chesapeake Affiliates in connection with their performance of the services outlined in the services agreement, solely to the extent that (x) such acts or omissions were performed or omitted at the direction of our general partner, and without material deviation therefrom, and (y) such services were performed in accordance with the standard of performance set forth in the services agreement, or (B) the Partnership Group’s gross negligence or willful misconduct.

Employee Secondment Agreement

Chesapeake, certain of its affiliates and our general partner have entered into an amended and restated employee secondment agreement pursuant to which specified employees of Chesapeake have been seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Additionally, all of our executive officers other than our chief executive officer, Mr. Stice, have been seconded to our general partner pursuant to this agreement. Our general partner, subject to specified exceptions and limitations, reimburses Chesapeake on a monthly basis for substantially all costs and expenses Chesapeake incurs relating to such seconded employees, including the cost of their salaries, bonuses and employee benefits, including 401(k), restricted stock grants and health insurance and certain severance benefits. For the twelve months ending December 31, 2011, our general partner reimbursed Chesapeake approximately $42.1 million for the services rendered by such seconded employees during such period.

The initial term of the employee secondment agreement extends through September 30, 2014. The term will automatically extend for additional twelve month periods unless any party provides 90 days’ prior written notice otherwise prior to the expiration of the initial term or the applicable twelve month period. Our general partner may terminate the agreement at any time upon 90 days’ prior written notice.

Employee Transfer Agreement

In order to provide for an efficient transition of seconded employees from their current joint employment relationship with our general partner and Chesapeake in the event that our general partner elects to establish a standalone workforce, Chesapeake, certain of its affiliates and our general partner entered into an amended and restated employee transfer agreement pursuant to which our

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general partner agreed to maintain certain compensation and benefits standards for seconded employees to whom our general partner makes offers of employment. Among other things, the employee transfer agreement limits the ability of our general partner to hire seconded employees from Chesapeake to situations where our general partner offers such seconded employee a base salary or hourly base wages, equal or greater than that which Chesapeake provides such seconded employee at the time of transfer and other compensation and benefits that, in the aggregate, are substantially comparable to those provided to such seconded employee at such time. Additionally, in the event of such an employee transfer, for a period of not less than twelve months thereafter, we are obligated to maintain the base salary or hourly wages, for such transferred employee of no less than that paid to such transferred employee immediately prior to the transfer date and other compensation and benefits for such transferred employee that, in the aggregate, are substantially comparable to those in effect immediately prior to the transfer date.

The employee transfer agreement has an indefinite term. However, the agreement is terminable (i) by the parties upon their mutual agreement, (ii) by any party upon another party’s failure to cure a material breach for 120 days, or (iii) by any party in the event that another party becomes insolvent.

Shared Services Agreement

In return for the services of Mr. Stice as the chief executive officer of our general partner, our general partner has entered into a shared services agreement with Chesapeake pursuant to which our general partner has agreed to reimburse certain of the costs and expenses incurred by Chesapeake in connection with Mr. Stice’s employment. Our general partner is generally expected, subject to certain exceptions, to reimburse Chesapeake for 50 percent of the costs and expenses of the amounts provided to Mr. Stice in his employment agreement; however, the ultimate reimbursement obligation is determined based on the amount of time Mr. Stice actually spends working for us. The reimbursement obligations of our general partner will continue for so long as Mr. Stice is employed by both our general partner and Chesapeake. Please read “Item 11. Executive Compensation—Employment Agreements—Agreement with J. Mike Stice, President and Chief Executive Officer” for a description of the costs, expenses and benefits afforded to Mr. Stice in connection with his employment agreement.

Gas Gathering Agreements

Barnett Shale Region and Mid-Continent Region

We have entered into 20-year natural gas gathering agreements with certain subsidiaries of Chesapeake and with Total pursuant to which we provide gathering, treating, compression and dehydration services for natural gas delivered by Chesapeake and Total to our gathering systems in our Barnett Shale region and, solely with respect to Chesapeake, our Mid-Continent region. Total Holdings USA Inc., a wholly owned subsidiary of Total S.A., has guaranteed the obligations of Total Gas & Power North America, Inc. and Total E&P USA, Inc. under the Total gas gathering agreement. These agreements provide us with dedication of all of the natural gas owned or controlled by Chesapeake and Total and produced from or attributable to existing and future wells located on oil, gas and mineral leases covering lands within the acreage dedications, excluding (i) any oil, gas and/or mineral leases purchased, in the case of Chesapeake after September 30, 2009, and in the case of Total after February 1, 2010, that were, at the time of purchase, subject to dedication to another gas gathering system not owned and operated by Chesapeake, and such dedication was not entered into in connection with such acquisition; (ii) certain reserved properties specified in the gas gathering agreement; and (iii) other non-material properties dedicated as of September 30, 2009 in the case of Chesapeake, or as of February 1, 2010, in the case of Total to another gas gathering system not owned and operated by Chesapeake. We generated the majority of our $565.9 million of revenues for the twelve months ending December 31, 2011 pursuant to these gas gathering agreements.

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Pursuant to our gas gathering agreements, Chesapeake and Total have committed to deliver specified minimum volumes of natural gas to our gathering systems that take production from the Barnett Shale for each year through December 31, 2018 and for the six month period ending June 30, 2019. The aggregate minimum volume commitments, approximately 75 percent of which will be attributed to Chesapeake and approximately 25 percent of which will be attributed to Total, begin at approximately 418 Bcf for the year ending December 31, 2010 (or an average of approximately 1.14 Bcf/d) and increase on an annual basis pursuant to the terms of the gas gathering agreement to approximately 493 Bcf for the year ending December 31, 2018 (or an average of 1.35 Bcf/d). Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Gas Gathering Agreements.” The minimum volume commitments may be reduced in certain instances, including a force majeure event affecting a system, a delayed connection or to the extent a system is unavailable due to inspections, alterations or repairs in excess of five days per month. In the event either Chesapeake or Total does not meet its minimum volume commitment to us, as adjusted in certain instances, for any annual period (or six-month period in the case of the six months ending June 30, 2019) during the minimum volume commitment period, Chesapeake or Total will be obligated to pay us a fee equal to the Barnett Shale fee for each Mcf by which the applicable party’s minimum volume commitment for the year (or six-month period) exceeds the actual volumes gathered on our systems attributable to the applicable party’s production. To the extent natural gas gathered on our systems from Chesapeake or Total during any annual period (or six-month period) exceeds such party’s minimum volume commitment for the period, Chesapeake or Total will be obligated to pay us the Barnett Shale fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitment of such party for the six months ending June 30, 2019 and then against the minimum volume commitments of each preceding year. In the event that the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the immediately preceding period.

We have certain connection obligations for new operated drilling pads and operated wells of Chesapeake and Total in the acreage dedications. Chesapeake and Total are required to provide us notice of new drilling pads and wells operated by Chesapeake or Total in the acreage dedications. During the minimum volume commitment period and subject to certain conditions specified in the gas gathering agreements, we are generally required to connect new operated drilling pads in the Barnett acreage dedication by the later of the date the wells commence production or 21 months after the date of the connection notice and, until June 30, 2019, to use our commercially reasonable efforts to connect new operated wells in the Mid-Continent area by the later of the date the wells commence production or 60 days after the date of the connection notice. If we fail to complete a connection in the Barnett acreage dedication by the required date, Chesapeake and Total, as their sole remedy for such delayed connection, are entitled to a delay in the minimum volume obligations for gas volumes that would have been produced from the delayed connection. After June 30, 2019, we only are required to make connections in the acreage dedications to new drilling pads and wells if we believe that the then current fees would allow us to earn an acceptable return on our investment, and if we decline to make a connection, Chesapeake and Total have certain rights to reimburse us for our connection costs or to request a release from the gathering agreement dedication of the affected wells. Chesapeake and Total also are required to notify us of their wells drilled in the acreage dedications that are operated by other parties and we have the option, but not the obligation, to connect non-operated wells to our gathering systems. If we decline to make a connection to a non-operated well, Chesapeake or Total, as the case may be, have certain rights to have the well released from the dedication under the gas gathering agreement.

A maximum daily quantity is also in effect with respect to the gathering systems that take production from the Barnett Shale. Generally, once daily volumes equal the maximum quantity specified for a particular system, we are no longer obligated to accept natural gas on such system. Under certain circumstances, however, where excess capacity is then available on an applicable

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gathering system, we may be required to accept such natural gas to the extent available and to provide “Priority 3 Service” with respect to such volumes. In most instances (and, where applicable, up to the maximum daily quantity), Chesapeake and Total are entitled to “Priority 1 Service.” If capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, the holders of Priority 1 Service will be curtailed last. Subject to certain limitations, we may commingle Chesapeake’s and Total’s natural gas with the natural gas of third parties.

Volumetric losses in Chesapeake’s or Total’s natural gas attributable to lost and unaccounted for natural gas, as well as volumetric reductions related to the use of fuel gas for gathering, compression, dehydrating, processing and treating, are, with respect to a particular gathering system, shared and allocated among Chesapeake, Total and other third-party shippers in the proportion that each party delivers gas to such system. We have agreed with Chesapeake and Total on a volumetric-based cap on fuel and lost and unaccounted for gas and electricity on our systems with respect to Chesapeake’s and Total’s volumes. In the event that we exceed the permitted cap in any covered period, we may incur significant expenses to replace the volume of natural gas used as fuel and lost or unaccounted for, or electricity, in excess of such cap based on then current natural gas and electricity prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

The agreements are fee-based, and we are paid a specified fee per Mcf for natural gas received on our gathering systems. The particular fees, which are subject to an automatic annual escalator at the beginning of each year, differ from one system to another and, in some cases, are based in part upon receipt point pressures. At specified intervals, we and each of Chesapeake and Total have the right to seek a redetermination of the fees for service on the Barnett gathering system. Such rights may be exercised during a six-month period beginning September 30, 2011 and a two-year period beginning September 30, 2014. A fee redetermination with respect to our Barnett Shale region under either agreement will apply to volumes from Chesapeake and Total under both agreements. The cumulative upward or downward fee adjustment for the Barnett Shale region is capped at 27.5 percent of the initial weighted average Barnett Shale fee (as escalated) as specified in the gas gathering agreement. The fee redetermination mechanism was designed to support a return on our invested capital as we meet our obligation to connect our customers’ operated wells to our gathering systems. An example of such variation may be the variation in fees generated on those systems where the fee is based in part upon receipt point pressures. If a fee redetermination is requested, we will determine an adjustment (upward or downward) to our Barnett Shale fee with Chesapeake and Total based on the factors specified in our gas gathering agreements, including, but not limited to: (i) differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the minimum volume commitment period made as of September 30, 2009 and (ii) differences between the revised estimates of our capital expenditures, compression expenses and revenues for the remainder of the minimum volume commitment period forecast as of the redetermination date and scheduled estimates thereof for the minimum volume commitment period made as of September 30, 2009. If we and Chesapeake or Total do not agree upon a redetermination of the Barnett Shale fee within 30 days of receipt of the request for the redetermination, an industry expert will be selected to determine adjustments to the Barnett Shale fee. A redetermined Barnett Shale fee will go into effect on the first day of the month following the date on which the adjusted fee is finally determined. The Mid-Continent fees will be redetermined at the beginning of each year through 2019. We will determine an adjustment to fees for the gathering systems in the region with Chesapeake based on the factors specified in the gas gathering agreement, including, but not limited to differences between our actual revenues, capital expenditures and compression expenses as of the redetermination date and the scheduled estimates of these amounts for the period ending June 30, 2019, referred to as the Mid-Continent redetermination period, made as of September 30, 2009. The annual upward or downward fee adjustment for the Mid-Continent region is capped at 15 percent of the then current fees at the time of redetermination.

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Chesapeake continues to own the gathering system located on the property leased from the Dallas-Fort Worth (“DFW”) Airport Authority in the Barnett Shale region, and we have been engaged to operate and maintain this gathering system. We receive as a fee for providing the operation and maintenance services an amount equal to all revenues derived from the operation of the DFW gathering system while we serve as the operator, including the fees paid by Chesapeake and Total under our gas gathering agreements. If our right to operate and maintain the DFW gathering system is terminated, Chesapeake is obligated to make a termination payment to us that equals the economic benefits we would have received if such termination had not occurred and to indemnify us for any other losses arising from such early termination.

The primary terms of the agreements continue through June 30, 2029, after which the agreements continue in effect on a year-to-year basis unless terminated by either party. We may terminate our gas gathering agreement with Chesapeake or Total if Chesapeake or Total fails to perform any of its material obligations, such failure is not excused by force majeure events and such failure is not remedied (or remedial action commenced) during a 60-day cure period. Chesapeake or Total may terminate if we fail to perform any of our material obligations. However, if our failure relates to only one or more facilities or gathering systems, Chesapeake or Total may terminate only as to such facility or system. Where Chesapeake or Total fails to pay us an undisputed amount when due, we may terminate if such failure is not remedied within 15 business days after we provide notice to Chesapeake or Total of such failure. We have entered into a guaranty with Chesapeake relating to, among other agreements, our gas gathering agreement with certain of its affiliates. The guaranty provided by Chesapeake is a guaranty of payment and performance and not of collection.

If either Chesapeake or Total sells, transfers or otherwise disposes to a third party properties within the acreage dedication in our Barnett Shale region and, solely with respect to Chesapeake, our Mid-Continent region, it will be required to cause the third party to either enter into our existing gas gathering agreement with Chesapeake or Total or enter into a new gas gathering agreement with us on substantially similar terms to our existing gas gathering agreement with Chesapeake or Total.

Haynesville Shale Region

In connection with the acquisition, on December 21, 2010, we entered into a 10-year natural gas gathering agreement with wholly-owned subsidiaries of Chesapeake, Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Empress, L.L.C. and Chesapeake Louisiana L.P. (collectively, “CHK Springridge”). Pursuant to the gas gathering agreement, we will provide gathering, treating, compression and dehydration services for natural gas delivered by CHK Springridge to our gathering system in the Springridge area of mutual interest. The gas gathering agreement provides us with a dedication of substantially all of the natural gas owned or controlled by CHK Springridge and produced from or attributable to existing and future wells located on oil, gas and mineral leases pertaining to the Haynesville and Bossier formations within the Springridge area of mutual interest.

Pursuant to the gas gathering agreement, CHK Springridge has committed to deliver specified minimum volumes of natural gas to our Springridge gathering system for each year from 2011 through 2013. The aggregate minimum volume commitments begin at approximately 103.7 Bcf for 2011 (or an average of approximately 0.284 Bcf/d) and increase on an annual basis pursuant to the terms of the gas gathering agreement to approximately 118.5 Bcf for 2012 (or an average of approximately 0.325 Bcf/d) and 134.6 Bcf for 2013 (or an average of 0.369 Bcf/d). T he minimum volume commitments may be reduced in certain instances. In the event CHK Springridge does not meet its minimum volume commitment, as adjusted in certain instances, for any annual period during the minimum volume commitment period, CHK Springridge will be obligated to pay us a fee equal to the Springridge fee for each Mcf by which CHK Springridge’s minimum volume commitment for the year exceeds the actual volumes gathered on the system attributable to CHK Springridge’s production. To the extent natural

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gas gathered on the system from CHK Springridge during any annual period exceeds CHK Springridge’s minimum volume commitment for the period, CHK Springridge will be obligated to pay us the Springridge fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitment of such CHK Springridge for 2013 and then against the minimum volume commitments of each preceding year. In the event that the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the immediately preceding period.

We have certain connection obligations similar to those under our existing gas gathering agreement in the Barnett Shale region. CHK Springridge is entitled to “Priority 1 Service.” If capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, the holders of Priority 1 Service will be curtailed last.

Volumetric losses in CHK Springridge’s natural gas attributable to lost and unaccounted for natural gas, as well as volumetric reductions related to the use of fuel gas for gathering, compression, dehydrating, processing and treating, are, with respect to a particular gathering system, shared and allocated among CHK Springridge and other third-party shippers in the proportion that each party delivers gas to such system.

The gas gathering agreement is fee-based, and we are paid a specified fee per Mcf for natural gas received on our gathering system. Volumes of natural gas that receive compression service will be subject to an additional compression fee. The fees are subject to an automatic annual escalator at the beginning of each year. The agreement also contains a fee redetermination mechanism. The fee redetermination mechanism was designed to support a return on our invested capital as we meet our obligation to connect our customers’ operated wells to our gathering systems. The first redetermination period will extend from December 1, 2010 through December 31, 2012, and subsequent redetermination periods will be the calendar years 2013 through 2020. An adjustment to fees for the gathering systems in the region with CHK Springridge will be determined based on the factors specified in the gas gathering agreement, including, but not limited to differences between our actual revenues, capital expenditures and compression expenses as of the redetermination date and the scheduled estimates of these amounts for the period ending December 31, 2020, made as of November 30, 2010. The annual upward or downward fee adjustment is capped at 15 percent of the then prevailing fees at the time of redetermination. If we and CHK Springridge do not agree upon a redetermination of the fees within 30 days after the commencement of a new redetermination period, an industry expert will be selected to determine adjustments to the fees pursuant to the redetermination provisions in the agreement. Redetermined fees will go into effect on the first day of the month following the date on which the adjusted fee is finally determined.

The primary term of the agreement continues through December 31, 2020, after which the agreement continues in effect on a year-to-year basis unless terminated by either party. We have entered into a guaranty with Chesapeake relating to, among other agreements, the gas gathering agreement. The guaranty provided by Chesapeake is a guaranty of payment and performance and not of collection.

Marcellus Shale Region

Through our acquisition of Appalachia Midstream Services, L.L.C. (“Appalachia Midstream”), we have entered into 15-year natural gas gathering agreements with certain subsidiaries of Chesapeake and other producers pursuant to which we provide gathering and compression services for natural gas delivered by Chesapeake and other producers to our gathering systems in our Marcellus Shale Region. We gather and compress natural gas in exchange for fees per MMBtu for natural gas gathered and per MMBtu for natural gas compressed. The gathering fees are redetermined annually, as described below. The compression fees escalate on January 1 of each year based on the consumer

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price index. In addition, CMD has committed to pay us quarterly any shortfall between the actual EBITDA from these assets and specified quarterly targets. The targets add to a total of $100 million in 2012 and $150 million in 2013.

Each January 1, gathering fees for each gathering system under the gas gathering agreements with Chesapeake and other producers are redetermined and adjusted based on the factors specified in the agreement, including our capital expenditures for the system, the total revenues and total expenses for the system and the targeted pre-income tax rate of return on capital invested. There is no cap on these fees.

We have the option to connect to new wells within the dedicated acreage. If we elect not to connect to any new well drilled by the producers within the dedicated acreage, the producers may elect to have such well, and any subsequent wells within a two-mile radius of the surface location of such well, permanently released from the dedication area, or the producers may elect to construct, at its expense, a gathering system to connect to such well (and wells within a one-mile radius of such well), in which case the producers would pay us a reduced gathering fee for natural gas we receive through the asset. Alternatively, the producers may require us to enter into an agreement pursuant to which we would construct the gathering system to connect to the well in exchange for a reimbursement by the producers of the costs we incur in connection therewith. The producers may elect to connect wells outside the dedicated area at its sole expense and pay us a reduced gathering fee for natural gas we receive from such wells, but gas from such outside wells will not be afforded the same priority as gas produced from wells located within the dedicated area.

Pursuant to our gas gathering agreements with the producers, we have agreed on a volumetric-based cap on fuel and lost and unaccounted for gas with respect to the producer’s volumes on the systems. If we exceed the permitted cap, we must provide a cost estimate for a remedy that is reasonably expected to prevent exceeding the permitted cap in the future. At the election of the producers, we may pay such costs (which costs would then be included in the gathering fee redetermination) or the producers may pay the costs. If we exceed the permitted cap and do not provide a proposal to the producers to prevent exceeding the cap in the future within the required time period, we may incur our proportionate share (based on our ownership interest in the applicable system) of significant fees in connection with the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this may subject us to direct commodity price risk.

Gas Compressor Master Rental and Servicing Agreement

We have entered into a gas compressor master rental and servicing agreement with MidCon Compression, LLC, a wholly owned indirect subsidiary of Chesapeake, pursuant to which MidCon Compression has agreed to lease to us certain compression equipment that we use to compress gas gathered on our gathering systems outside the Marcellus Shale and provide certain related services. In return for the lease of such equipment, we have agreed to pay specified monthly rates per specified compression units, subject to an annual escalator to be applied on October 1st of each year and a redetermination of such specified monthly rates to market rates effective no later than October 1, 2016. Under the compression agreement, we have granted MidCon Compression the exclusive right to lease and rent compression equipment to us in the acreage dedications through September 30, 2016. Thereafter, we will have the right to continue leasing such equipment through September 30, 2019 at market rental rates to be agreed upon between the parties or to lease compression equipment from unaffiliated third parties. MidCon Compression guarantees to us that the leased compressors will meet specified run time and throughput performance guarantees. The monthly rental rates are reduced for any leased equipment that does not meet these guarantees. We lease substantially all of the compression capacity for our existing gathering systems in the Marcellus Shale from MidCon Compression under a long-term contract expiring on January 31, 2021 pursuant to which we have

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agreed to pay specified monthly rates under a fixed-fee structure subject to an annual escalator. This agreement is not subject to an exclusivity provision. Compressor rental charges from affiliates were $57.6 million, $47.8 million and $11.7 million for the years ended December 31, 2011 and 2010 and three months ended December 31, 2009, respectively. Compressor rental charges from affiliates were $47.3 million for the nine months ended September 30, 2009, respectively, for our predecessor.

We are obligated to maintain general liability and property insurance, including machinery breakdown insurance with respect to the leased equipment. In addition, MidCon Compression has agreed to provide us with emission testing and other related services at monthly rates. We may terminate these services upon not less than six months notice, and MidCon Compression may terminate these services at any time after September 30, 2011 upon not less than six months notice.

The compression agreement with respect to our gathering systems outside the Marcellus Shale expires on September 30, 2019, and our compression agreement with respect to our gathering systems in the Marcellus Shale expires on January 31, 2021, but each agreement will continue from year to year after their respective expiration dates, unless terminated by us no less than 60 days prior to the end of the term or any year thereafter. Additionally, either party may terminate in specified circumstances, including upon the other party’s failure to perform material obligations under the compression agreement if such failure is not cured within 60 days after notice thereof.

In connection with the acquisition, on December 21, 2010, the agreement with respect to our gathering systems outside the Marcellus Shale was amended and restated to include the area of mutual interest associated with the Springridge natural gas gathering system and to allow for the addition of future areas of mutual interest.

Inventory Purchase Agreement

We have entered into an inventory purchase agreement pursuant to which we have agreed beginning as of September 30, 2009 to purchase from Chesapeake, in each case on terms and conditions to be mutually agreed upon by Chesapeake and us, our first $60.0 million of requirements of pipes that are useful in the conduct of the natural gas gathering, compression, dehydrating, treating and transportation business at a specified price per ton. For the years ended December 31, 2011 and 2010, we purchased approximately $23.4 million and $36.6 million, respectively, of inventory pursuant to this inventory purchase agreement satisfying the terms of this agreement.

Marketing and Noncompete Agreements

Pursuant to marketing and noncompete agreements, we have agreed to appoint Chesapeake Energy Marketing, Inc., a wholly owned indirect subsidiary of Chesapeake (which we refer to as CEMI), as our agent to purchase, at our request, gas on behalf of us, at agreed market responsive prices and for an agreed marketing fee, to settle accrued gas imbalances on our gathering systems. As consideration for such agreements, we have agreed to not engage in activities to purchase or market natural gas in the acreage dedications specified in the respective agreements if CEMI or its affiliates are then performing, or willing to perform, such activities on our behalf. Additionally, each of CEMI and Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P., DD Jet Limited, LLP and Empress L.L.C., each wholly owned indirect subsidiaries of Chesapeake, has agreed not to, and to cause Chesapeake not to, directly or indirectly, engage in or participate in activities to gather or transport natural gas in the acreage dedications specified in the respective agreements, whether for their own account or on behalf of third parties.

The marketing and noncompete agreement with respect to the Barnett Shale Region and Mid-Continent Region expires on September 30, 2019, the marketing and noncompete agreement with

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respect to the Haynesville Shale Region expires on December 31, 2020, and the marketing and noncompete agreement with respect to the Marcellus Shale Region expires on January 31, 2021. Each agreement will continue from month to month after its respective expiration date, unless terminated by either party upon no less than 30 days’ prior notice. Additionally, either party may terminate in specified circumstances, including upon the other party’s failure to perform material obligations under the compression agreement if such failure is not cured within 60 days after notice thereof.

Master Recoupment, Netting and Setoff Agreement

We have entered into a master recoupment, netting and setoff agreement with Chesapeake and certain of its subsidiaries. The recoupment agreement provides for the netting of fees, liquidated damages and other charges between the parties to certain “covered agreements,” including the gas gathering agreement with Chesapeake, the gas compressor master rental and servicing agreement, the services agreement, the employee secondment agreement and the employee transfer agreement. The recoupment agreement provides for the parties’ right to recoup, net and setoff accrued and unpaid fees, reimbursements, late payment charges and interest, and liquidated damages for breach or early termination pursuant to specified obligations arising under the terms of the covered agreements and losses, damages and other amounts to the extent agreed by the parties or provided by a court order. Recoupment, netting and setoff rights are triggered by a “recoupment event,” defined as the failure to pay an accrued payment obligation or obligations exceeding $100,000 under a covered agreement. Under the agreement, if a “triggering event,” defined as bankruptcy or insolvency, occurs, the non-bankrupt/insolvent party has the right to hold funds due from it to the bankrupt/insolvent party as an offset to liquidated amounts due from the bankrupt/insolvent party to the non-bankrupt/insolvent party, pending resolution of the parties’ rights under the recoupment agreement or common law. This agreement will terminate in the event there are fewer than two “covered agreements” in effect, or earlier upon written agreement of the parties.

Surety Bond Indemnification Agreement

We have agreed to indemnify Chesapeake and certain affiliates of Chesapeake against any loss or expense with respect to certain surety bonds issued for our benefit and for which we are obligated to provide indemnity insurance to Chesapeake. We may also be required to indemnify Chesapeake in connection with future surety bond issuances made for our benefit. Our currently outstanding surety bonds relate to certain well, pipeline and litigation obligations in New Mexico, Oklahoma and Texas. These indemnification obligations will not expire until all bond obligations for which we are liable for indemnification to Chesapeake are released.

Trademark License Agreement

We have entered into a trademark license agreement with Chesapeake Energy Corporation pursuant to which it has agreed to grant to us a license to use the mark “Chesapeake” in the trade name and service mark “Chesapeake Midstream Partners.” Such license is a royalty-free, fully paid up, nonexclusive and nontransferable right and license to use such marks solely in connection with the midstream natural gas business. Subject to certain exceptions, the trademark license agreement will continue until December 31, 2019. Either party may terminate in the event of a material breach by the other party that is not cured within 30 days of written notice thereof.

Registration Rights Agreement

We have entered into a registration rights agreement with Chesapeake and GIP pursuant to which we have granted each of Chesapeake and GIP and certain of their affiliates certain demand and “piggyback” registration rights. Under the registration rights agreement, each of Chesapeake and GIP

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and certain of their affiliates generally have the right to require us to file a registration statement for the public sale of all of the equity interests in the Partnership, including common and subordinated units and incentive distribution rights (collectively, “partnership securities”) owned by it. In addition, if we sell any partnership securities in a registered underwritten offering, each of Chesapeake and GIP and certain of their affiliates have the right, subject to specified limitations, to include its partnership securities in that offering.

We are obligated to pay all expenses relating to any demand or piggyback registration, except for expenses relating to underwriting including to underwriters’ or brokers’ commission or discounts.

Springridge Acquisition

On December 16, 2010, we entered into an asset purchase agreement with Louisiana Midstream Gas Services, L.L.C., and Chesapeake Midstream Development, L.P. (collectively, the “Seller Parties”), and, for certain limited purposes, Chesapeake Midstream Management, L.L.C. All of the parties are subsidiaries or affiliates of Chesapeake. Pursuant to the terms of the purchase agreement, we agreed to acquire all of the Seller Parties’ right, title and interest in and to assets and assume certain liabilities associated with the Springridge natural gas gathering system in the Haynesville Shale, other than certain excluded assets and retained obligations.

The acquisition closed on December 21, 2010, with an economic effective date of December 1, 2010. The purchase price for the acquisition consisted of $500.0 million, subject to post-closing adjustment, which was financed with a draw on our revolving credit facility of approximately $234.0 million plus approximately $266.0 million of cash on hand.

Pursuant to the purchase agreement and subject to specified limitations, the Seller Parties have agreed to indemnify us, our affiliates, and the respective officers, directors, employees, partners, members, equity holders, agents and investment advisers of any of the foregoing against certain losses resulting from any breach of any representations, warranties and covenants of the Seller Parties, and for certain other matters. We agreed to indemnify the Seller Parties, their affiliates, and the respective officers, directors, employees, partners, members, equity holders, agents and investment advisers of any of the foregoing against certain losses resulting from any breach by us of any representations, warranties and covenants, and for certain other matters.

In connection with the acquisition, we entered into a natural gas gathering agreement, an amended and restated gas compressor master rental and servicing agreement, and a marketing and noncompete agreement, each as described above under “—Agreements with Affiliates—Gas Gathering Agreements—Haynesville Shale Region,” “—Gas Compressor Master Rental and Servicing Agreement” and “—Marketing and Noncompete Agreement.”

All of the parties to the acquisition and related agreements described herein are subsidiaries or affiliates of Chesapeake. The terms of the acquisition and related agreements were approved by our general partner’s board of directors and by the board’s conflicts committee. The conflicts committee, a committee comprised of the independent members of our general partner’s board of directors, retained independent legal and financial advisors to assist it in evaluating and negotiating the acquisition. In approving the acquisition, the conflicts committee based its decision in part on an opinion from the independent financial advisor that the consideration to be paid by us was fair, from a financial point of view, to us.

Marcellus Acquisition

On December 28, 2011, Chesapeake MLP Operating, L.L.C. (“Buyer”), one of our wholly owned subsidiaries, entered into a Unit Purchase Agreement (the “Purchase Agreement”) with Chesapeake

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Midstream Operating, L.L.C. (“Seller”), Appalachia Midstream, Chesapeake Midstream Development, L.P. (“CMD,” and together with Seller and Appalachia Midstream, the “Seller Parties”), and, for certain limited purposes, Chesapeake Midstream Management, L.L.C. (“CMM”) and the Partnership. Pursuant to the terms of the Purchase Agreement, Buyer agreed to acquire from Seller 1,000 units of AMS representing 100 percent of the issued and outstanding membership units of AMS.

In connection with the acquisition, CMD has committed to pay us quarterly any shortfall between the actual EBITDA from these assets and specified quarterly targets, with the quarterly targets adding to a total of $100 million in 2012 and $150 million in 2013.

The acquisition closed on December 29, 2011, with an effective date of December 31, 2011. The total consideration, which is subject to a customary post-closing working capital adjustment, for the acquisition was $879.3 million, consisting of 9,791,605 common units and $600.0 million in cash that was financed with a draw on our revolving credit facility.

Pursuant to the Purchase Agreement and subject to specified limitations, the Seller Parties agreed to indemnify Buyer, its affiliates, and the respective officers, directors, employees, partners, managers and members of any of the foregoing against certain losses resulting from any breach of any representations, warranties and covenants of the Seller Parties, and for certain other matters. The Buyer has agreed to indemnify the Seller Parties, their affiliates, and the respective officers, directors, employees, partners, managers and members of any of the foregoing against certain losses resulting from any breach of any representations, warranties and covenants of the Buyer, and for certain other matters.

In connection with the acquisition, through Appalachia Midstream we entered into natural gas gathering agreements with Chesapeake and other producers, a gas compressor master rental and servicing agreement, and a marketing and noncompete agreement, each as described above under “—Agreements with Affiliates—Gas Gathering Agreements—Marcellus Shale Region,” “—Gas Compressor Master Rental and Servicing Agreement” and “—Marketing and Noncompete Agreement.”

All of the parties to the acquisition and related agreements described herein are subsidiaries or affiliates of Chesapeake. The terms of the acquisition and related agreements were approved by our general partner’s board of directors and by the board’s conflicts committee. The conflicts committee, a committee consisting of the independent members of our general partner’s board of directors, retained independent legal and financial advisors to assist it in evaluating and negotiating the acquisition. In approving the acquisition, the conflicts committee based its decision in part on an opinion from the independent financial advisor that the consideration to be paid by us was fair, from a financial point of view, to us.

Review, Approval or Ratification of Transactions with Related Persons

Our Code of Ethics sets forth our policies for the review, approval and ratification of transactions with related persons. Under the Code of Ethics, a director is expected to bring to the attention of the chief executive officer or the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict will be addressed in accordance with Chesapeake Midstream Venture’s and our general partner’s organizational documents and the provisions of our partnership agreement. The resolution may be determined by disinterested directors, our general partner’s board of directors and/or the conflicts committee of our general partner’s board of directors.

Pursuant to the Code of Ethics, any executive officer of our general partner is required to avoid conflicts of interest unless approved by the board of directors.

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In the case of any sale of equity by us to an owner or affiliate of an owner of our general partner, we must obtain general approval of our general partner’s board of directors for the transaction. The board may delegate authority to set the specific terms of such a sale of equity to a pricing committee.

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Chesapeake, GIP and Chesapeake Midstream Ventures, on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of its fiduciary duty.

Our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our unitholders if the resolution of the conflict is:

• approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval;

• approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

• fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Our general partner may, but is not required under our partnership agreement to, seek the approval of such resolution from the conflicts committee of its board of directors. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to reasonably believe he is acting in the best interests of the partnership.

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Director Independence

The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner. For a discussion of the independence of the board of directors of our general partner, please see “Item 10. Directors, Executive Officers and Corporate Governance—Management of the Partnership.”

ITEM 14. Principal Accountant Fees and Services

We have engaged PricewaterhouseCoopers LLP as our independent registered public accounting firm. The following table summarizes the fees we have paid PricewaterhouseCoopers LLP to audit the Partnership’s annual consolidated financial statements and for other services for each of the last two fiscal years:

	2011		2010
	(in thousands)		(in thousands)
Audit fees	$	909	$	920
Audit-related fees		127		150
Tax		225		183
Total	$	1,261	$	1,253

Audit fees are primarily for audit of the Partnership’s consolidated financial statements and reviews of the Partnership’s financial statements included in the Form 10-Qs.

Audit-related fees include the audit and review, respectively, of the Marcellus gas gathering system financial statements for the year ended December 31, 2010, and nine months ended September 30, 2011.

Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice and tax planning. This category primarily includes services relating to the preparation of unitholder annual K-1 statements.

Audit Committee Approval of Audit and Non-Audit Services

The Audit Committee of the Partnership’s general partner has adopted a Pre-Approval Policy with respect to services which may be performed by PricewaterhouseCoopers LLP. This policy lists specific audit-related services as well as any other services that PricewaterhouseCoopers LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional Audit Committee authorization. The Audit Committee receives quarterly reports on the status of expenditures pursuant to that Pre-Approval Policy. The Audit Committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the Audit Committee or by its Chairman, to whom such authority has been conditionally delegated, prior to engagement. During 2011, no fees for services outside the scope of audit, review, or attestation that exceed the waiver provisions of 17 CFR 210.2-01(c)(7)(i)(C) were approved by the Audit Committee.

The Audit Committee has approved the appointment of PricewaterhouseCoopers LLP as independent registered public accounting firm to conduct the audit of the Partnership’s consolidated financial statements for the year ended December 31, 2011.

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PART IV

ITEM 15. Exhibits and Financial Statement Schedules

(a) The following documents are filed as part of this report:

1. Financial Statements.  Chesapeake’s consolidated financial statements are included in Item 8 of this report. Reference is made to the accompanying Index to Financial Statements.

2. Financial Statement Schedules.  Schedule II is included in Item 8 of this report with our consolidated financial statements. No other financial statement schedules are applicable or required.

3. Exhibits.  The following exhibits are filed herewith pursuant to the requirements of Item 601 of Regulation S-K:

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form		SEC File Number		Exhibit		Filing Date		Filed Herewith	Furnished Herewith
2.1	Asset Purchase Agreement by and among Louisiana Midstream Gas Services, L.L.C., Chesapeake Midstream Development, L.P. and Magnolia Midstream Gas Services L.L.C., and, for certain limited purposes, Chesapeake Midstream Management, L.L.C., dated as of December 16, 2010		8-K		001-34831		2.1		12/22/2010
2.2	Unit Purchase Agreement by and among Chesapeake MLP Operating, L.L.C., Chesapeake Midstream Operating, L.L.C., Chesapeake Midstream Development, L.P. and Appalachia Midstream Services, L.L.C., and, for certain limited purposes, Chesapeake Midstream Management, L.L.C. and Chesapeake Midstream Partners, L.P., dated December 28, 2011		8-K		001-34831		2.1		01/04/2012
3.1	Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P.		S-1		333-164905		3.1		02/16/2010

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		Incorporated by Reference
Exhibit Number	Exhibit Description	Form		SEC File Number		Exhibit		Filing Date		Filed Herewith	Furnished Herewith
3.2	First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. dated August 3, 2010		8-K		001-34831		3.1		08/05/2010
3.3	Second Amended and Restated Limited Liability Company Agreement of Chesapeake MLP Operating, L.L.C., dated August 3, 2010		8-K		001-34831		3.2		08/05/2010
4.1	Indenture, dated as of April 19, 2011, by and among the Partnership, Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee		8-K		001-34831		4.1		04/20/2011
4.2	Registration Rights Agreement, dated as of April 19, 2011, by and among the Partnership, Finance Corp, the General Partner, the Guarantors named therein and the representatives of the Initial Purchasers named therein		8-K		001-34831		4.2		04/20/2011
4.3	Indenture, dated as of January 11, 2012, by and among the Partnership, Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee		8-K		001-34831		4.1		01/11/2012
4.4	Registration Rights Agreement, dated as of January 11, 2012, by and among the Partnership, Finance Corp, the General Partner, the Guarantors named therein and the representatives of the Initial Purchasers named therein		8-K		001-34831		4.2		01/11/2012

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		Incorporated by Reference
Exhibit Number	Exhibit Description	Form		SEC File Number		Exhibit		Filing Date		Filed Herewith	Furnished Herewith
10.1	Contribution, Conveyance and Assumption Agreement by and among Chesapeake Midstream Partners, L.P., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Holdings, L.L.C., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P., Chesapeake Midstream Ventures, L.L.C. and Chesapeake MLP Operating, L.L.C., dated as of July 28, 2010		8-K		001-34831		10.1		07/30/2010
10.2	Omnibus Agreement by and among Chesapeake Midstream Holdings, L.L.C., Chesapeake Midstream Ventures, L.L.C. and Chesapeake Midstream Partners, L.P., dated August 3, 2010		8-K		001-34831		10.1		08/05/2010
10.3	Amended and Restated Services Agreement by and among Chesapeake Midstream Management, L.L.C., Chesapeake Operating, Inc., Chesapeake Midstream GP, L.L.C, Chesapeake Midstream Partners, L.P. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010		8-K		001-34831		10.2		08/05/2010
10.4	Amended and Restated Employee Transfer Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream Management, L.L.C., Chesapeake Midstream GP, L.L.C. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010		8-K		001-34831		10.3		08/05/2010

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Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

10.5

Amended and Restated Employee Secondment Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream Management, L.L.C., Chesapeake Midstream GP, L.L.C., Chesapeake Operating, Inc. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010

8-K

001-34831

10.4

08/05/2010

10.6*

Amended and Restated Shared Services Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream GP, L.L.C., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010

8-K

001-34831

10.5

08/05/2010

10.7

Registration Rights Agreement by and among Chesapeake Midstream Partners, L.P., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P. and Chesapeake Midstream Holdings, L.L.C., dated August 3, 2010

8-K

001-34831

10.6

08/05/2010

10.9*

Chesapeake Midstream Long-Term Incentive Plan

S-1

333-164905

10.18

07/20/2010

10.9.1*

Form of Restricted Unit Award Agreement for Long-Term Incentive Plan

10-K

001-34831

10.10.1

03/11/2011

156

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

10.10

Amended and Restated Gas Gathering Agreement, dated January 25, 2010, by and among Chesapeake Midstream Partners, L.L.C., Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P. and DDJET Limited LLP

S-1

333-164905

10.2

07/26/2010

10.10.1†

Amendment to Amended and Restated Gas Gathering Agreement, dated March 8, 2011, by and among Chesapeake Midstream Partners, L.L.C., Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P. and DDJET Limited L.L.P.

10-K

001-34831

10.22

03/11/2011

10.11

Barnett Gas Gathering Agreement, dated January 25, 2010, by and among Chesapeake Midstream Partners, L.L.C., Total Gas & Power North America, Inc. and Total E&P USA, Inc.

S-1

333-164905

10.3

07/26/2010

10.12†

Gas Gathering Agreement, dated December 21, 2010, by and among Magnolia Midstream Gas Services, L.L.C., Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Empress, L.L.C. and Chesapeake Louisiana L.P.

10-K

001-34831

10.13

03/11/2011

10.13

Gas Compressor Master Rental and Servicing Agreement, dated September 30, 2009, between Midcon Compression, LLC and Chesapeake Midstream Partners, L.L.C.

S-1

333-164905

10.8

04/09/2010

157

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

10.13.1†

Amended and Restated Gas Compressor Master Rental and Servicing Agreement, effective as of December 21, 2010, between MidCon Compression, LLC and Chesapeake MLP Operating, L.L.C.

10-K

001-34831

10.15

03/11/2011

10.14

Additional Agreement, dated January 25, 2010, by and among Chesapeake Midstream Partners, L.L.C., Total Gas & Power North America, Inc., Total E&P USA, Inc., Chesapeake Energy Marketing, Inc., Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P., DDJET Limited LLP and Chesapeake Operating, Inc.

S-1

333-164905

10.4

07/26/2010

10.15

*

Amended and Restated Chesapeake Midstream Management Incentive Compensation Plan

X

10.15.1

*

Award Agreement under Chesapeake Midstream Management Incentive Compensation Plan - Robert S. Purgason

S-1

333-164905

10.20

07/06/2010

10.15.2

*

Award Agreement under Chesapeake Midstream Management Incentive Compensation Plan-David C. Shiels

S-1

333-164905

10.21

07/06/2010

10.16

*

Amended and Restated Employment Agreement of J. Mike Stice, dated as of November 10, 2011

X

10.16.1

*

Amendment to Employment Agreement of J. Mike Stice, dated as of December 22, 2011

X

10.17

*

Employment Agreement of Robert S. Purgason

S-1

333-164905

10.14

07/06/2010

10.18

*

Employment Agreement of David C. Shiels

S-1

333-164905

10.15

07/06/2010

158

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

10.19

Amended and Restated Credit Agreement among Chesapeake MLP Operating, L.L.C., as the Borrower, Chesapeake Midstream Partners, L.P., as the Parent, Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and the Issuing Lender, and the other Lenders party thereto, dated as of June 10, 2011.

8-K

001-34831

10.1

06/16/2011

10.19.1

Amendment No. 1 to Amended and Restated Credit Agreement among Chesapeake MLP Operating, L.L.C., as the Borrower, Chesapeake Midstream Partners, L.P., as the Parent, Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and the Issuing Lender, and the other Lenders party thereto, dated as of December 20, 2011

8-K

001-34831

10.1

12/27/2011

12.1

Ratio of Earnings to Fixed Charges

X

21.1

Subsidiaries of Chesapeake Midstream Partners, L.P.

X

23.1

Consent of Pricewaterhouse Coopers, LLP

X

31.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X

31.2

David C. Shiels, Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X

32.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

X

159

			Incorporated by Reference
Exhibit Number		Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith	Furnished Herewith
	32.2	David C. Shiels, Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.							X
	101.INS	XBRL Instance Document							X
	101.SCH	XBRL Taxonomy Extension Schema Document							X
	101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document							X
	101.DEF	XBRL Taxonomy Extension Definition Linkbase Document							X
	101.LAB	XBRL Taxonomy Extension Labels Linkbase Document							X
	101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document							X

† Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

* Management contract or compensatory plan or arrangement.

160

Signatures

Pursuant to the requirements of Section 13 or 15(d) 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.

	CHESAPEAKE MIDSTREAM PARTNERS, L.P. By: Chesapeake Midstream GP, L.L.C., its general partner
Date: February 29, 2012	By	/S/    J. MIKE STICE
		J. Mike Stice Chief Executive Officer

161

POWER OF ATTORNEY

Each person whose signature appears below constitutes and appoints J. Mike Stice and David C. Shiels, and each of them, either one of whom may act without joinder of the other, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all amendments to this Annual Report on Form 10-K, and to file the same, with all, exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each, and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, and each of them, or the substitute or substitutes of any or all of them, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Capacity	Date
/s/  J. MIKE STICE	Chief Executive Officer (Principal Executive Officer)	February 29, 2012
J. Mike Stice
/s/  DAVID C. SHIELS David C. Shiels	Chief Financial Officer (Principal Financial and Accounting Officer)	February 29, 2012
/s/  DAVID A. DABERKO	Chairman of the Board and Director	February 29, 2012
David A. Daberko
/s/  PHILIP L. FREDERICKSON	Director	February 29, 2012
Philip L. Frederickson
/s/  MATTHEW C. HARRIS	Director	February 29, 2012
Matthew C. Harris
/s/  SUEDEEN G. KELLY	Director	February 29, 2012
Suedeen G. Kelly
/s/  AUBREY K. MCCLENDON	Director	February 29, 2012
Aubrey K. McClendon
/s/  Domenic J. Dell’Osso	Director	February 29, 2012
Domenic J. Dell’Osso
/s/  WILLIAM A. WOODBURN	Director	February 29, 2012
William A. Woodburn

162

INDEX TO EXHIBITS

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form		SEC File Number		Exhibit		Filing Date		Filed Herewith	Furnished Herewith
2.1	Asset Purchase Agreement by and among Louisiana Midstream Gas Services, L.L.C., Chesapeake Midstream Development, L.P. and Magnolia Midstream Gas Services L.L.C., and, for certain limited purposes, Chesapeake Midstream Management, L.L.C., dated as of December 16, 2010		8-K		001-34831		2.1		12/22/2010
2.2	Unit Purchase Agreement by and among Chesapeake MLP Operating, L.L.C., Chesapeake Midstream Operating, L.L.C., Chesapeake Midstream Development, L.P. and Appalachia Midstream Services, L.L.C., and, for certain limited purposes, Chesapeake Midstream Management, L.L.C. and Chesapeake Midstream Partners, L.P., dated December 28, 2011		8-K		001-34831		2.1		01/04/2012
3.1	Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P.		S-1		333-164905		3.1		02/16/2010
3.2	First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. dated August 3, 2010		8-K		001-34831		3.1		08/05/2010
3.3	Second Amended and Restated Limited Liability Company Agreement of Chesapeake MLP Operating, L.L.C., dated August 3, 2010		8-K		001-34831		3.2		08/05/2010
4.1	Indenture, dated as of April 19, 2011, by and among the Partnership, Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee		8-K		001-34831		4.1		04/20/2011

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form		SEC File Number		Exhibit		Filing Date		Filed Herewith	Furnished Herewith
4.2	Registration Rights Agreement, dated as of April 19, 2011, by and among the Partnership, Finance Corp, the General Partner, the Guarantors named therein and the representatives of the Initial Purchasers named therein		8-K		001-34831		4.2		04/20/2011
4.3	Indenture, dated as of January 11, 2012, by and among the Partnership, Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee		8-K		001-34831		4.1		01/11/2012
4.4	Registration Rights Agreement, dated as of January 11, 2012, by and among the Partnership, Finance Corp, the General Partner, the Guarantors named therein and the representatives of the Initial Purchasers named therein		8-K		001-34831		4.2		01/11/2012
10.1	Contribution, Conveyance and Assumption Agreement by and among Chesapeake Midstream Partners, L.P., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Holdings, L.L.C., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P., Chesapeake Midstream Ventures, L.L.C. and Chesapeake MLP Operating, L.L.C., dated as of July 28, 2010		8-K		001-34831		10.1		07/30/2010
10.2	Omnibus Agreement by and among Chesapeake Midstream Holdings, L.L.C., Chesapeake Midstream Ventures, L.L.C. and Chesapeake Midstream Partners, L.P., dated August 3, 2010		8-K		001-34831		10.1		08/05/2010

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

10.3

Amended and Restated Services Agreement by and among Chesapeake Midstream Management, L.L.C., Chesapeake Operating, Inc., Chesapeake Midstream GP, L.L.C, Chesapeake Midstream Partners, L.P. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010

8-K

001-34831

10.2

08/05/2010

10.4

Amended and Restated Employee Transfer Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream Management, L.L.C., Chesapeake Midstream GP, L.L.C. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010

8-K

001-34831

10.3

08/05/2010

10.5

Amended and Restated Employee Secondment Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream Management, L.L.C., Chesapeake Midstream GP, L.L.C., Chesapeake Operating, Inc. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010

8-K

001-34831

10.4

08/05/2010

10.6*

Amended and Restated Shared Services Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream GP, L.L.C., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010

8-K

001-34831

10.5

08/05/2010

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

10.7

Registration Rights Agreement by and among Chesapeake Midstream Partners, L.P., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P. and Chesapeake Midstream Holdings, L.L.C., dated August 3, 2010

8-K

001-34831

10.6

08/05/2010

10.9*

Chesapeake Midstream Long-Term Incentive Plan

S-1

333-164905

10.18

07/20/2010

10.9.1*

Form of Restricted Unit Award Agreement for Long-Term Incentive Plan

10-K

001-34831

10.10.1

03/11/2011

10.10

Amended and Restated Gas Gathering Agreement, dated January 25, 2010, by and among Chesapeake Midstream Partners, L.L.C., Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P. and DDJET Limited LLP

S-1

333-164905

10.2

07/26/2010

10.10.1†

Amendment to Amended and Restated Gas Gathering Agreement, dated March 8, 2011, by and among Chesapeake Midstream Partners, L.L.C., Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P. and DDJET Limited L.L.P.

10-K

001-34831

10.22

03/11/2011

10.11

Barnett Gas Gathering Agreement, dated January 25, 2010, by and among Chesapeake Midstream Partners, L.L.C., Total Gas & Power North America, Inc. and Total E&P USA, Inc.

S-1

333-164905

10.3

07/26/2010

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

10.12†

Gas Gathering Agreement, dated December 21, 2010, by and among Magnolia Midstream Gas Services, L.L.C., Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Empress, L.L.C. and Chesapeake Louisiana L.P.

10-K

001-34831

10.13

03/11/2011

10.13

Gas Compressor Master Rental and Servicing Agreement, dated September 30, 2009, between Midcon Compression, LLC and Chesapeake Midstream Partners, L.L.C.

S-1

333-164905

10.8

04/09/2010

10.13.1†

Amended and Restated Gas Compressor Master Rental and Servicing Agreement, effective as of December 21, 2010, between MidCon Compression, LLC and Chesapeake MLP Operating, L.L.C.

10-K

001-34831

10.15

03/11/2011

10.14

Additional Agreement, dated January 25, 2010, by and among Chesapeake Midstream Partners, L.L.C., Total Gas & Power North America, Inc., Total E&P USA, Inc., Chesapeake Energy Marketing, Inc., Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P., DDJET Limited LLP and Chesapeake Operating, Inc.

S-1

333-164905

10.4

07/26/2010

10.15

*

Amended and Restated Chesapeake Midstream Management Incentive Compensation Plan

X

10.15.1

*

Award Agreement under Chesapeake Midstream Management Incentive Compensation Plan - Robert S. Purgason

S-1

333-164905

10.20

07/06/2010

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

10.15.2

*

Award Agreement under Chesapeake Midstream Management Incentive Compensation Plan-David C. Shiels

S-1

333-164905

10.21

07/06/2010

10.16

*

Amended and Restated Employment Agreement of J. Mike Stice, dated as of November 10, 2011

X

10.16.1

*

Amendment to Employment Agreement of J. Mike Stice, dated as of December 22, 2011

X

10.17

*

Employment Agreement of Robert S. Purgason

S-1

333-164905

10.14

07/06/2010

10.18

*

Employment Agreement of David C. Shiels

S-1

333-164905

10.15

07/06/2010

10.19

Amended and Restated Credit Agreement among Chesapeake MLP Operating, L.L.C., as the Borrower, Chesapeake Midstream Partners, L.P., as the Parent, Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and the Issuing Lender, and the other Lenders party thereto, dated as of June 10, 2011.

8-K

001-34831

10.1

06/16/2011

10.19.1

Amendment No. 1 to Amended and Restated Credit Agreement among Chesapeake MLP Operating, L.L.C., as the Borrower, Chesapeake Midstream Partners, L.P., as the Parent, Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and the Issuing Lender, and the other Lenders party thereto, dated as of December 20, 2011

8-K

001-34831

10.1

12/27/2011

12.1

Ratio of Earnings to Fixed Charges

X

			Incorporated by Reference
Exhibit Number		Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith		Furnished Herewith
	21.1	Subsidiaries of Chesapeake Midstream Partners, L.P.						X
	23.1	Consent of Pricewaterhouse Coopers, LLP						X
	31.1	J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.						X
	31.2	David C. Shiels, Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.						X
	32.1	J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.								X
	32.2	David C. Shiels, Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.								X
	101.INS	XBRL Instance Document								X
	101.SCH	XBRL Taxonomy Extension Schema Document								X
	101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document								X
	101.DEF	XBRL Taxonomy Extension Definition Linkbase Document								X
	101.LAB	XBRL Taxonomy Extension Labels Linkbase Document								X
	101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document								X

† Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

* Management contract or compensatory plan or arrangement.

EX-10.15

EXHIBIT 10.15

CHESAPEAKE MIDSTREAM

MANAGEMENT INCENTIVE COMPENSATION PLAN

(as Amended and Restated)

I. Purpose of Plan

The Chesapeake Midstream Management Incentive Compensation Plan, as hereby amended and restated (the “Plan”), is intended to provide a method of attracting, motivating and retaining individuals of outstanding competence and ability, and to motivate and encourage those individuals to devote their best efforts to the development and growth of the Partnership, thereby advancing the interests of the Partnership and its equity owners.

II. Definitions and Construction

2.1 Definitions. Where the following words and phrases are used in the Plan, they shall have the respective meanings set forth below, unless the context clearly indicates to the contrary:

(a) “Affiliate” means any corporation, partnership, limited liability company or partnership, association, trust or other organization which, directly or indirectly, controls, is controlled by, or is under common control with, the Partnership. For purposes of the preceding sentence, “control” (including, with correlative meanings, the terms “controlled by” and “under common control with”), as used with respect to any entity or organization, shall mean the possession, directly or indirectly, of the power (i) to vote 50% or more of the securities or equity interests having ordinary voting power for the election of directors of the controlled entity or organization, or (ii) to direct or cause the direction of the management and policies of the controlled entity or organization, whether through the ownership of voting securities or equity interests or by contract or otherwise.

(b) “Annual Payment Percentage” means, with respect to a Fiscal Year, the following: Fiscal Year 2010 – 20%; Fiscal Year 2011 – 25%; Fiscal Year 2012 – 33-1/3%; Fiscal Year 2013 – 50%; and Fiscal Year 2014 – 100%, unless provided otherwise in a Participant’s Award Agreement.

(c) “Award Agreement” means a written agreement between the Company (or an Affiliate) and an employee evidencing the award of a Participation Interest in the Plan and specifying the Participant’s Excess Return Percentage and Equity Uplift Value Percentage.

(d) “Board” means the board of managers of the JV; provided, however, if the JV no longer exists, “Board” shall mean the board of managers or other governing body of the Plan Sponsor.

(e) “Cause” shall have the meaning set forth in the Participant’s written employment agreement with the Company or an Affiliate; however, if the Participant does not have such an employment agreement, “Cause” means (i) the Participant’s breach or threatened breach of any written employment agreement between the Company and the Participant; (ii) the Participant’s neglect of duties or failure to act, other than by reason of disability or death; (iii) the misappropriation, fraudulent conduct, or acts of workplace dishonesty by the Participant with respect to the assets or operations of the Company or any of its Affiliates; (iv) the Participant’s failure to comply with directives from superiors or written Company policies; (v) the Participant’s personal misconduct which injures the Company or an Affiliate and/or reflects poorly on the Company’s and/or an Affiliate’s reputation; (vi) the Participant’s failure to perform the Participant’s duties; or (vii) the conviction of the Participant for, or a plea of guilty or no contest to, a felony or any crime involving moral turpitude. Any rights the Company or an Affiliate may have hereunder in respect of an event giving rise to Cause shall be in addition to the rights the Company or Affiliate may have under any other agreement with the Participant or at law or in equity.

(f) “Change of Control” shall have the meaning set forth in the Participant’s written employment agreement with the Company or an Affiliate; however, if the Participant does not have such an employment agreement, “Change of Control” means, and shall be deemed to have occurred upon, any of the following events: (a) any “person” or “group” within the meaning of those terms as used in Sections 13(d) and 14(d)(2) of the Securities Exchange Act of 1933, other than Chesapeake Energy Corporation, Global Infrastructure Management, LLC or an Affiliate of either, (a “Third Party”) shall become the direct or indirect beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of more than 50% of the voting power of the voting securities of the general partner (or board of management, if applicable) of the Partnership (such entity, the “General Partner”); or (b) the sale of other disposition, including by way of liquidation, by either the Partnership or the General Partner of all or substantially all of its assets, whether in a single or series of related transactions, to one or more Third Parties. Notwithstanding the foregoing, a Change of Control must also constitute a “change of control” within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended, and the regulations thereunder. For clarity, the IPO was not a Change of Control.

(g) “Company” means Chesapeake Midstream Management, L.L.C.

(h) “Dilution Adjustment” means, with respect to a Participant’s Excess Return Percentage and Equity Uplift Value Percentage, as set forth in his or her Award Agreement, the product of such applicable percentage and a fraction, the numerator of which is the number of Units outstanding on the closing date of the IPO, and the denominator of which is (1) with respect to the Participant’s Excess Return Percentage applicable for a specified fiscal quarter in a Fiscal Year, the number of Units outstanding on the record date for the distribution made with respect to the applicable fiscal quarter and (2) with respect to the Participant’s Equity Uplift Value Percentage, the total number of Units outstanding on the Equity Uplift Payment Date. Appropriate adjustment shall be made to the Dilution Adjustments to give effect to any Unit splits, combinations or similar adjustments occurring after the date of any Award Agreement and prior to an applicable Excess Return payment date or the Equity Uplift Payment Date.

(i) “Disability” shall have the meaning set forth in the Participant’s employment agreement with the Company or an Affiliate; however, if the Participant does not have such an employment agreement, “Disability” means a disability that entitles the Participant to long-term disability benefits under a long-term disability plan of the Company or an Affiliate.

-2-

(j) “Distributed Cash” means, with respect to a fiscal quarter in a Fiscal Year, the amount of cash distributed by the Partnership, as applicable, to its equity owners (excluding distributions to the general partner of the Partnership) with respect to such fiscal quarter of that Fiscal Year, as authorized by the Board (or deemed authorized pursuant to the JV’s organizational documents).

(k) “Equity Uplift Payment Date” means the fifth anniversary of the date of the Participant’s Award Agreement or, if earlier, the date of a Change of Control.

(l) “Equity Uplift Value” means the product of A x B, where “A” is the Excess Unit Value and “B” is the number of Units outstanding on the Equity Uplift Payment Date.

(m) “Equity Uplift Value Percentage” means the Participant’s diluted percentage participation in the Equity Uplift Value, as set forth in his or her Award Agreement, subject to any Dilution Adjustment.

(n) “Excess Return” means, with respect to a fiscal quarter in a Fiscal Year, the excess (if any) of the Distributed Cash with respect to such fiscal quarter over the Preferred Return for that fiscal quarter.

(o) “Excess Return Percentage” means, with respect to a Participant for a fiscal quarter in a Fiscal Year, the percentage participation by such Participant in the Excess Return, if any, for that Fiscal Year, as set forth in his or her Award Agreement, adjusted for any Dilution Adjustment applicable for that fiscal quarter in the Fiscal Year.

(p) “Excess Unit Value” means the excess, if any, of (i) the Unit Value on Equity Uplift Payment Date over (ii) the IPO Unit Value.

(q) “Fiscal Year” means one of the following calendar years, as applicable: 2010, 2011, 2012, 2013 and 2014, unless provided otherwise in a Participant’s Award Agreement.

(r) “Good Reason” shall have the meaning set forth in the Participant’s written employment agreement with the Company or an Affiliate; however, if the Participant does not have such an employment agreement, “Good Reason” means (1) the elimination of the Participant’s job position, (2) a material reduction in the Participant’s duties, (3) the reassignment of the Participant to a new position of materially less authority, or (4) a material reduction in the Participant’s base salary. Notwithstanding the preceding provisions or any other provision in the Plan to the contrary, any assertion by a Participant of a termination of employment for “Good Reason” shall not be effective unless all of the following conditions are satisfied: (A) the condition described in the preceding sentence giving rise to such Participant’s termination of employment must have arisen without such Participant’s consent; (B) such Participant must provide written notice to the Board of such condition within 90 days of the initial existence of the condition; (C) the condition specified in such notice must remain uncorrected for 30 days after receipt of such notice by the Board; and (D) the date of such Participant’s termination of employment must occur within 30 days after the lapse of the 30-day period specified in subclause (C) above.

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(s) “IPO” means the initial public offering of equity interests of the Partnership on The New York Stock Exchange.

(t) “IPO Equity Value” means $2,901,197,124.00.

(u) “IPO Unit Value” means $21.00. Appropriate adjustments shall be made to the IPO Unit Value to give affect to any Unit splits, combinations or similar adjustments occurring after the date of any Award Agreement and prior to the Equity Uplift Payment Date.

(v) “JV” means Chesapeake Midstream Ventures, L.L.C. or any successor entity that is owned and controlled by the parties that control the JV as of the initial date of this Plan.

(w) “Participant” means an employee of the Company or an Affiliate who has been awarded a Participation Interest pursuant to Section 3.2.

(x) “Participation Interest” means an interest awarded under the Plan to a Participant pursuant to an Award Agreement for the purpose of measuring the incentive compensation payable under the Plan to such Participant. A Participation Interest shall represent a contingent right to receive a specified Excess Return Percentage of the Excess Return and a specified Equity Uplift Value Percentage of the Equity Uplift Value, subject to the further terms and conditions of the Plan. A Participation Interest shall exist only for purposes of the Plan and matters related hereto. In no event shall any holder of a Participation Interest, by virtue of an award of such interest made under the Plan, have any (i) security or other interest in any assets of the Company, the Partnership or any Affiliate, (ii) right to receive any equity or other interest in the Company, the Partnership or any Affiliate, or (iii) rights as an equity or other interest holder in the Company, the Partnership or any Affiliate.

(y) “Partnership” means Chesapeake Midstream Partners, L.P. or any successor thereto.

(z) “Plan” means the Chesapeake Midstream Management Incentive Compensation Plan, as amended from time to time.

(aa) “Plan Sponsor” means the Company or any entity that assumes sponsorship of the Plan and becomes liable for the payment of the awards granted under the Plan.

(bb) “Preferred Return” means, with respect to a fiscal quarter in a Fiscal Year: the product of (1) 1.5% and (2) the sum of (i) the IPO Equity Value and (ii) the gross value of all Units issued by the Partnership after the date of the IPO and prior to the record date for the distributions made with respect to the applicable fiscal quarter in such Fiscal Year. For this purpose, the gross value of the newly issued Units shall be calculated at the time of their issuance and shall be equal to the product of (i) the number of new Units then being issued and (ii) the fair market value per Unit at the time of such issuance, as determined in good faith by the Board.

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(cc) “Special Committee” means the Special Committee of the JV, as defined in the Participants’ employment agreements.

(dd) “Unit” means all units of the Partnership (other than general partner units).

(ee) “Unit Value” means the average closing sales price per Unit for the 30 trading days immediately preceding the Equity Uplift Payment Date, as reported in The Wall Street Journal or such other reporting service approved by the Board, in its discretion. In the event that the price per Unit is not so reported, Unit Value means the fair market value of a Unit as determined in good faith by the Board. If, however, the Equity Uplift Payment Date is the date of a Change of Control, Unit Value shall be the Unit value paid by the acquirer on the date of the Change of Control.

2.2 Number and Gender. Wherever appropriate herein, words used in the singular shall be considered to include the plural, and words used in the plural shall be considered to include the singular. The masculine gender, where appearing in the Plan, shall be deemed to include the feminine gender.

2.3 Headings. The headings of Articles, Sections, and Paragraphs herein are included solely for convenience. If there is any conflict between such headings and the text of the Plan, the text shall control. All references to Articles, Sections, and Paragraphs are to the Plan unless otherwise indicated.

2.4 Governing Law. Except to the extent federal law applies and preempts state law, the Plan shall be construed, enforced, and administered according to the laws of the State of Oklahoma, excluding any conflict-of-law rule or principle that might refer construction of the Plan to the laws of another state or country.

2.5 Severability. In case any provision of the Plan is determined by a court of competent jurisdiction to be illegal, invalid, or unenforceable for any reason, such illegal, invalid, or unenforceable provision shall not affect the remaining provisions of the Plan, and the Plan shall be construed and enforced as if such illegal, invalid, or unenforceable provision had not been included therein.

III. Eligibility; Awards of Participation Interests

3.1 Eligibility. Each key member of management of the Company or an Affiliate who performs work for the Company, the JV, the Partnership, or either the general partner or a “subsidiary” of the Partnership is eligible to be awarded a Participation Interest under the Plan.

3.2 Participation Interests. Participation Interests shall be entered into only with those eligible employees selected to be Participants in the discretion of the Board from time to time and at such times as the Board may determine. In connection with each Participation Interest, the Board shall determine (a) subject to the terms and conditions of the Plan and the

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related Award Agreement, the percentage of the Excess Return for a Fiscal Year (if any) and the Equity Uplift Value that the holder of such Participation Interest shall have the contingent right to receive, and (b) the other terms, provisions, conditions and limitations of such award. The terms and provisions of each award of a Participation Interest, as determined by the Board in its sole discretion, shall be set forth in an Award Agreement, which shall incorporate by reference, and be subject to, the terms and provisions of the Plan. Each Award Agreement shall contain such provisions not inconsistent with the Plan as the Board deems appropriate. The terms and provisions set forth in Award Agreements may vary among Participants.

IV. Determinations of Incentive Compensation Payments

4.1 Determination of Excess Return for a Fiscal Year. As soon as reasonably practical after the end of a Fiscal Year (but in no event later than 60 days following the last day of such Fiscal Year), the Board shall cause the amount of the Excess Return for that Fiscal Year, if any, to be determined.

4.2 Excess Return Payments. (a) Subject to Paragraph 4.2(c), as soon as reasonably practical after the amount of the Excess Returns for the fiscal quarters in a Fiscal Year have been determined by the Board, the Plan Sponsor shall pay to each Participant who then holds a Participation Interest an amount equal to the sum of the following calculations for each of the four fiscal quarters for that Fiscal Year; the product of (A x B) x C, where “A” is the amount of the Excess Return for that fiscal quarter, “B” is the Participant’s Excess Return Percentage applicable for that fiscal quarter (as adjusted by any applicable Dilution Adjustment), and “C” is the Annual Payment Percentage for that Fiscal Year. Once the Participant’s payment for a Fiscal Year is determined as provided in the foregoing sentence, such amount shall be paid to the Participant in each calendar year subsequent to that Fiscal Year until the sum of the Annual Payment Percentages for all payments made to the Participant with respect to that Fiscal Year equals 100%. Notwithstanding the foregoing however, except as provided below and in Paragraphs 4.2(b) and 4.3(b), upon a Participant’s termination of employment with the Company and its Affiliates for any reason whatsoever, such Participant automatically shall forfeit on such termination his or her Participation Interest and no payments shall thereafter be due or payable under the Plan to such Participant with respect to such forfeited Participation Interest. In the event a Participant who is proposed to be terminated is hired by the JV or the MLP Employer (as defined in the Participant’s applicable employment agreement), such Participant shall not be treated as having terminated his or her employment with the Company and its Affiliates on such “transfer” for purposes of this Section 4.2.

(b) If a Participant’s employment with the Company and its Affiliates is terminated (i) due to the Participant’s death or Disability, (ii) by the Company or an Affiliate other than for Cause, or (iii) by the Participant for a Good Reason, the Participant shall be paid, with respect to each Fiscal Year that has lapsed in full (if any) as of his or her date of termination, an amount equal to the sum of the following calculations for each of the four fiscal quarters for such fully lapsed Fiscal Year: the product of (A x B)—C, where “A” is the Excess Return for such fiscal quarter, “B” is the Participant’s Excess Return Percentage with respect to such fiscal quarter (as adjusted by any applicable Dilution Adjustment), and “C” is the sum of the amounts that have already been paid to the Participant pursuant to Paragraph 4.2(a) with respect to such lapsed Fiscal Year. Payment under this Paragraph 4.2(b) shall be made by the Plan Sponsor within 60 days of the Participant’s termination of employment and thereafter no further amounts shall be due and payable to such Participant pursuant to this Section 4.2.

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(c) Notwithstanding anything in Paragraph 4.2(a) to the contrary, upon a Change of Control, or as soon as reasonably practical thereafter, but in no event later than 60 days following the Change of Control, the Plan Sponsor shall pay to each Participant who is an employee of the Company or an Affiliate on the date immediately preceding the date of the Change of Control an amount, with respect to each Fiscal Year that has lapsed in full prior to such Change of Control, equal to the sum of the following calculations for each of the four fiscal quarters for such fully lapsed Fiscal Year: the product of (A x B)—C, where “A” is the Excess Return for such fiscal quarter, “B” is the Participant’s Excess Return Percentage with respect to such fiscal quarter (as adjusted by any applicable Dilution Adjustment), and “C” is the sum of the amounts that have already been paid to the Participant pursuant to Paragraph 4.2(a) with respect to such lapsed Fiscal Year. Thereafter no further amounts shall be due and payable to such Participant pursuant to this Section 4.2.

4.3 Equity Uplift Payments. (a) Subject to Paragraph 4.3(c), as soon as reasonably practical, but in no event later than 60 days, following the Equity Uplift Payment Date, the Plan Sponsor shall pay to each Participant an amount equal to the product of the Equity Uplift Value, if any, and the Participant’s Equity Uplift Value Percentage. Notwithstanding the foregoing however, except as otherwise provided below and in Paragraphs 4.3(b) and (c), upon a Participant’s termination of employment with the Company and its Affiliates for any reason whatsoever prior to the payment of the Participant’s percentage of the Equity Uplift Value, such Participant automatically shall forfeit his or her Participation Interest and no percentage of the Equity Uplift Value thereafter shall be due or payable to such Participant with respect to his or her forfeited Participation Interest. In the event a Participant who is proposed to be terminated is hired by the JV or the MLP Employer (as defined in the Participant’s applicable employment agreement), such Participant shall not be treated as having terminated his or her employment with the Company and its Affiliates on such “transfer” for purposes of this Section 4.3.

(b) Subject to Paragraph 4.3(c), if a Participant’s employment with the Company and its Affiliates is terminated (i) due to the Participant’s death or Disability, (ii) by the Company or an Affiliate other than for Cause, or (iii) by the Participant for a Good Reason, the Plan Sponsor shall pay such Participant, as soon as reasonably practical, but in no event later than 60 days, following the Equity Uplift Payment Date, an amount equal to (A x B) x C, where “A” is the Equity Uplift Value, “B” is the Participant’s Equity Uplift Value Percentage, and “C” is a fraction, the numerator of which is the number of full Fiscal Years that have lapsed as of the Participant’s termination of employment date, and the denominator of which is five.

(c) Notwithstanding anything in Paragraphs 4.3(a) or (b) to the contrary, upon a Change of Control or as soon as reasonably practical thereafter, but in no event later than 60 days following the date of the Change of Control, (i) each Participant who is an employee of the Company or an Affiliate on the date immediately preceding the date of the Change of Control shall be paid by the Plan Sponsor an amount equal to the product of the Equity Uplift Value, if any, and the Participant’s Equity Uplift Value Percentage, and (ii) each Participant whose employment with the Company and its Affiliates terminated prior to the Change of Control due to the Participant’s death or Disability, by the Company or an Affiliate other than for Cause, or

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by the Participant for a Good Reason shall be paid by the Plan Sponsor an amount equal to the product of (x) the Equity Uplift Value, if any, and (y) the Participant’s Equity Uplift Value Percentage, multiplied by a fraction, the numerator of which is the number of full calendar months that have lapsed from the date of the Participant’s Award Agreement through the Participant’s termination of employment date, and the denominator of which is the number of full calendar months that have lapsed from the date of the Participant’s Award Agreement through the end of the calendar month preceding the date of the Change of Control. Thereafter no further amounts shall be payable to such Participant pursuant to this Section 4.3.

4.4 Payment Form. All payments required pursuant to this Plan shall be paid by the Plan Sponsor in the form of a single lump sum in cash; provided, however, in the discretion of the Board, all or any part of a Participant’s Equity Uplift Value payment may be paid in Units (the number of such Units being determined based on the value of a Unit on the Equity Uplift Payment Date).

4.5 Board Discretion. Notwithstanding anything in Sections 4.2 or 4.3 to the contrary, the Board, in its discretion, may waive all or part of the automatic forfeiture provisions of the Plan whenever it deems such waiver to be appropriate. Any such actions by the Board with respect to a Participant shall not be binding on the Board with respect to any other Participant in a similar circumstance.

4.6 Attachment A Example. The example in Attachment A attached to the Plan showing how various calculations under the Plan are to be made is hereby made a part of this Plan for all purposes and such calculations shall control over any written descriptions of the same herein if such written descriptions are in conflict with such example, unless the Board, in its sole discretion, determines otherwise.

V. Administration

5.1 Powers and Duties. The Board (or its delegate) shall supervise the administration and enforcement of the Plan according to the terms and provisions hereof and shall have the full discretionary authority and all of the powers necessary to accomplish these purposes. Without limiting the generality of the foregoing, the Board shall have all of the powers and duties specified for it under the Plan, including the power, right, and authority: (a) to select eligible employees to receive Participation Interests under the Plan; (b) to determine all provisions, conditions, and terms relating to any Participation Interest, including, without limitation, determinations as to the percentages set forth therein and any dilution thereof; (c) from time to time to establish rules and procedures for the administration of the Plan, which are not inconsistent with the provisions of the Plan, and any such rules and procedures shall be effective as if included in the Plan; (d) to construe in its sole discretion all terms, provisions, conditions, and limitations of the Plan and any Award Agreement; (e) to correct any defect or to supply any omission or to reconcile any inconsistency that may appear in the Plan (including Attachment A) or an Award Agreement in such manner and to such extent as the Board shall deem appropriate; (f) to make a determination in its discretion as to the right of any person to a payment with respect to a Participation Interest and the amount of such payment; and (g) to make all other determinations necessary or advisable for the administration of the Plan.

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5.2 Delegation of Authority. All decisions, determinations and actions to be made or taken by the Board pertaining to the Plan, an Award Agreement or a Participation Interest, and all determinations with respect to a Participant’s employment with the Company or an Affiliate or a termination of employment for purposes of the Plan, shall be made by the Board. All such decisions, determinations, and actions by the Board shall be final, binding and conclusive on all persons. The Board shall not be liable for any decision, determination or action taken or omitted to be taken in connection with the administration of the Plan. Furthermore, the Board in its discretion may delegate to one or more employees of the Company or an Affiliate all or some of its day-to-day ministerial duties and powers under the Plan.

VI. Nature of Plan

The establishment of the Plan shall not be deemed to create a trust. The Plan shall constitute an unfunded, unsecured liability of the Plan Sponsor to make payments in accordance with the provisions of the Plan, and no individual shall have any security interest or other interest in any assets or equity interests of the Plan Sponsor or an Affiliate.

VII. Termination and Amendment

The Board may from time to time, in its discretion, amend, in whole or in part, any or all of the provisions of the Plan or terminate the Plan in whole or in part; provided, however, that the Plan may not be amended or terminated in a manner that would materially adversely impact the contingent rights of any Participant under his or her Participation Interest with respect to (i) an Excess Return payment based on a Fiscal Year that has then lapsed in full, or (ii) an Equity Uplift payment based on its accrued value, if any, as of the effective date of such Plan termination or amendment, in either case without the consent of such Participant. Notwithstanding the foregoing, no amendment may be made to the Plan without the written consent of the Special Committee. The Plan shall automatically terminate on a Change of Control, and a Participant’s rights with respect to payment pursuant to Sections 4.2 and 4.3 shall survive such termination.

VIII. Miscellaneous Provisions

8.1 No Effect on Employment Relationship. Nothing in the adoption of the Plan, the award of a Participation Interest or the payment of any amounts hereunder shall confer on any person the right to continued employment by the Company or any of its Affiliates, or affect in any way the right of the Company or any Affiliate to terminate such employment at any time for any reason.

8.2 Prohibition Against Assignment or Encumbrance. (a) No right or benefit hereunder shall be assignable or transferable, or liable for, or charged with any of the torts or obligations of a Participant or any person claiming under a Participant, or be subject to seizure by any creditor of a Participant or any person claiming under a Participant. Other than by will or the applicable laws of descent and distribution, no Participant or any person claiming under a Participant shall have the power to anticipate or dispose of any right or payment hereunder in any manner.

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(b) Except as provided in Paragraph 8.2(a) above, neither the Plan nor any rights or obligations hereunder of the parties can be transferred or assigned without the written consent of the other parties to the Plan and the Special Committee.

8.3 Tax Treatment and Withholding. All payments under the Plan shall be treated by the Company and the Affiliates and the Participants as payments of compensation for services rendered and shall be reported by the Company and the Affiliates (as the case may be) to the relevant tax authorities as such. As a condition to the receipt of a payment under the Plan, each Participant irrevocably agrees to report such payment to the relevant tax authorities as a payment of compensation for services rendered. All payments made by the Company or an Affiliate as provided herein and shall be reduced by any amounts required to be withheld by the Company or the Affiliate under applicable local, state, federal or other tax law.

8.4 Section 409A. Contrary Plan or Award Agreement provisions notwithstanding, with respect to a Participant who is identified as a “specified employee” (within the meaning of Section 409A(a)(2)(B)(i) of the Code and as determined by the Company in accordance with any of the methods permitted under the regulations issued under Section 409A of the Code) and who is to receive a payment hereunder (which payment is not a “short-term deferral” or otherwise exempt from Section 409A of the Code) on account of such Participant’s “separation from service” (within the meaning of Section 409A(a)(2)(A)(i) of the Code), the payment to such Participant shall not be made prior to the earlier of (i) the date that is six months after the Participant’s separation from service or (ii) the date of death of the Participant. In such event, any payment to which the Participant would have otherwise been entitled during the first six months following the Participant’s separation from service (or, if earlier, prior to the Participant’s date of death) shall be accumulated and paid in the form of a single lump sum payment to the Participant (without interest) on the date that is six months after the Participant’s separation from service or to the Participant’s estate on the date of the Participant’s death, as applicable.

In addition, contrary Plan or Award Agreement provisions notwithstanding, the payment of any amount otherwise due under an Award Agreement or the Plan shall not be accelerated if such payment is subject to Section 409A of the Internal Revenue Code of 1986, as amended, unless such acceleration complies with the requirements of Section 409A and the Treasury regulations thereunder so as to not be subject to the additional tax imposed by Section 409A.

8.5 JV Employs a Participant. If the JV or any of its Affiliates exercises its right pursuant to a Participant’s employment agreement, any amendment thereto or otherwise, to employ a Participant who is proposed to be terminated by the Company or an Affiliate, the JV agrees to reimburse the Plan Sponsor for payments made to such Participant under the Plan (if any) after the date the JV or its Affiliate employs such Participant. Such “transfer” of employment shall not be treated as a termination of employment for purposes of Sections 4.2 and 4.3.

8.6 Third Party Beneficiaries. The JV shall be a beneficiary of all of the terms and provisions of the Plan and is entitled to enforce all rights hereunder as a party hereto.

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EXECUTED this February 27, 2012, effective for all purposes as of December 1, 2011.

BOARD OF MANAGERS CHESAPEAKE MIDSTREAM VENTURES, L.L.C.
/s/ Aubrey K. McClendon
Name:	Aubrey K. McClendon
/s/ Domenic J. Dell’Osso
Name:	Domenic J. Dell’Osso
/s/ Mathew C. Harris
Name:	Mathew Harris
/s/ William Woodburn
Name:	William Woodburn

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Attachment A

to the

Chesapeake Midstream Management Incentive Compensation Plan

IA. EXAMPLE OF ANNUAL EXCESS RETURN CALCULATIONS

WITHOUT ANY DILUTION ADJUSTMENTS

(dollar amounts, in millions)

		YEAR 2010			YEAR 2011			YEAR 2012			YEAR 2013			YEAR 2014
1.	Cash Distributions	$	200.0		$	220.0		$	240.0		$	260.0		$	280.0
2.	Preferred Return1		<147.0>			<147.0>			<147.0>			<147.0>			<147.0>
3.	Excess Return (1-2)	$	53.0		$	73.0		$	93.0		$	113.0		$	133.0
4.	Participant’s Excess Return Percentage		.10	%		.10	%		.10	%		.10	%		.10	%
5.	Participant’s Share of “Pool” (3 x 4)	$	0.053		$	0.073		$	0.093		$	0.113		$	0.133
6.	Annual Payment Percentages (across) and Years Payable (down)
	2010		.20			.20			.20			.20			.20
	2011					.25			.25			.25			.25
	2012								.333			.333			.333
	2013											.50			.50
	2014														1.0
7.	Amount Payable to Participant for a Fiscal Year (5 x 6)
	2010	$	0.011		$	0.011		$	0.011		$	0.011		$	0.011
	2011				$	0.018		$	0.018		$	0.018		$	0.018
	2012							$	0.031		$	0.031		$	0.031
	2013										$	0.057		$	0.057
	2014													$	0.133
	Total Amount Payable in a Fiscal Year (sum of item 7 amounts for that Fiscal Year)	$	0.011		$	0.029		$	0.060		$	0.116		$	0.249

¹  Assumes LP equity value at IPO of $2.450 billion.

IB. EXAMPLE OF ANNUAL EXCESS RETURN CALCULATIONS

WITH DILUTION ADJUSTMENTS

(dollar amounts, in millions)

The dilution adjustment assumes the following: (i) IPO Equity Value of $2.450 billion, (ii) 122.5 million LP units outstanding upon completion of IPO, and (iii) $220 million of units issued each year beginning in year 2011 and 149.4 million LP units outstanding at end of year 2014, resulting in a reduction of the Participant’s Excess Return Percentage from .10% to .082%. *

		YEAR 2010			YEAR 2011			YEAR 2012			YEAR 2013			YEAR 2014
1.	Cash Distributions	$	200.0		$	249.1		$	292.7		$	338.3		$	385.8
2.	Preferred Return		<147.0>			<159.9>			<172.9>			<185.8>			<198.7>
3.	Excess Return (1-2)	$	53.0		$	89.2		$	119.9		$	152.5		$	187.1
4.	Participant’s Excess Return Percentage*		.10	%		.094	%		.089	%		.085	%		.082	%
5.	Participant’s Share of “Pool” (3 x 4)	$	0.053		$	0.084		$	0.107		$	0.130		$	0.153
6.	Annual Payment Percentages (across) and Years Payable (down)
	2010		.20			.20			.20			.20			.20
	2011					.25			.25			.25			.25
	2012								.333			.333			.333
	2013											.50			.50
	2014														1.0
7.	Amount Payable to Participant for a Fiscal Year (5 x 6)
	2010	$	0.011		$	0.011		$	0.011		$	0.011		$	0.011
	2011				$	0.021		$	0.021		$	0.021		$	0.021
	2012							$	0.036		$	0.036		$	0.036
	2013										$	0.065		$	0.065
	2014													$	0.153
	Total Amount Payable in a Fiscal Year (sum of item 7 amounts for that Fiscal Year)	$	0.011		$	0.032		$	0.067		$	0.132		$	0.286

* The Preferred Return for a Fiscal Year and the Dilution Adjustment to a Participant’s Excess Return Percentage for a Fiscal Year are calculated by using the number of Units outstanding as of each of the record dates for the distributions made with respect to the fiscal quarters for that Fiscal Year.

IIA. EXAMPLE OF EQUITY UPLIFT CALCULATION FOR IPO IN 2010 AND NO DILUTION

ADJUSTMENT

1. IPO date Unit Value	$	20
2. Uplift Payment Date Unit Value	$	32
3. Excess Uplift Value (2 – 1)	$	12
4. Units Outstanding on Uplift Payment Date		122.5 million
5. Total Excess Uplift Value (3 x 4)	$	1.470 billion
6. Participant’s Uplift Value Percentage		0.10	%
7. Payment to Participant (5 x 6)	$	1.470 million

IIB. EXAMPLE OF EQUITY UPLIFT CALCULATION FOR IPO IN 2010 WITH DILUTION

ADJUSTMENT

The dilution adjustment assumes the following: (i) IPO Equity Value of $2.450 billion, (ii) 122.5 million LP units outstanding upon completion of IPO, and (iii) $220 million of units issued each year beginning in year 2011 and 149.4 million LP units outstanding at end of year 2014, resulting in a reduction of the Participant’s Uplift Value Percentage interest from .10% to .082%.

1. IPO date Unit Value	$	20
2. Uplift Payment Date Unit Value	$	36.14
3. Excess Uplift Value (2 – 1)	$	16.14
4. Units Outstanding on Uplift Payment Date		149.4 million
5. Total Excess Uplift Value (3 x 4)	$	2.411 billion
6. Participant’s Uplift Value Percentage		0.082	%
7. Payment to Participant (5 x 6)	$	1.978 million

EX-10.16

Exhibit 10.16

AMENDED AND RESTATED EMPLOYMENT AGREEMENT

THIS AGREEMENT is made effective November 10, 2011, between CHESAPEAKE ENERGY CORPORATION, an Oklahoma corporation (the “Company”), and JOHN M. STICE, an individual (the “Executive”).

W I T N E S S E T H:

WHEREAS, the Company previously retained the services of the Executive under the Employment Agreement dated effective November 10, 2008, (the “Prior Agreement”); and

WHEREAS, the Company and the Executive desire to amend and restate the Prior Agreement in its entirety to incorporate the foregoing and other changes to the employment arrangement between the Company and the Executive and to extend the term of the Prior Agreement as provided in Section 5.

NOW, THEREFORE, in consideration of the mutual promises herein contained, the Company and the Executive agree as follows:

1. Employment. The Company hereby employs the Executive and the Executive hereby accepts such employment subject to the terms and conditions contained in this Agreement. The Executive is engaged as an Executive of the Company, and the Executive and the Company do not intend to create a joint venture, partnership or other relationship which might impose a fiduciary obligation on the Executive or the Company in the performance of this Agreement.

2. Executive’s Duties. The Executive is employed on a full-time basis. Throughout the term of this Agreement, the Executive will use the Executive’s best efforts and due diligence to assist the Company in achieving the most profitable operation of the Company and the Company’s affiliated entities consistent with developing and maintaining a quality business operation. The Executive shall also devote all of Executive’s working time, attention and energies to the performance of Executive’s duties and responsibilities under this Agreement.

2.1 Specific Duties. The Executive will serve as Senior Vice President – Natural Gas Projects, President and Chief Operating Officer – Chesapeake Midstream Development, L.P. (“CMD”), and Chief Executive Officer – Chesapeake Midstream GP, L.L.C. (“GP”) for the Company, and in such other positions as might be mutually agreed upon by the parties. The Executive shall perform all of the duties required to fully and faithfully execute the office and position to which the Executive is appointed, and such other duties as may be reasonably requested by the Executive’s supervisor. During the term of this Agreement, the Executive may be nominated for election or appointed to serve as a director or officer of any of the Company’s affiliated entities as determined in such affiliates’ Board of Directors’ sole discretion. The services of the Executive will be requested and directed by the Company’s Chief Executive Officer, Mr. Aubrey K. McClendon.

2.2 Rules and Regulations. The Company has issued various policies and procedures applicable to employees and the Executive including an Employment Policies Manual which sets forth the general human resources policies of the Company and addresses frequently asked questions regarding the Company. The Executive agrees to comply with such policies and procedures except to the extent inconsistent with this Agreement. Such policies and procedures may be changed or adopted in the sole discretion of the Company without advance notice.

2.3 Stock Investment. The Executive acknowledges that the Executive is expected to hold shares of the Company’s common stock and common units of Chesapeake Midstream Partners, L.P. (“MLP”) such that the total number of shares and units held by the Executive equals at least ten thousand (10,000) in the aggregate at all times after November 10, 2011 and prior to termination of the Agreement. In the event the Executive’s stock investment is less than 10,000 shares and units, the Executive will have a grace period of ninety (90) days to restore the Executive’s stock investment to the guideline amount. The Compensation Committee of the Board of Directors (the “Compensation Committee”) may, in its discretion, extend the grace period for complying with the Executive’s stock investment guideline. The Company has no obligation to sell to or to purchase from the Executive any of the Company’s stock or units in connection with this paragraph and has made no representations or warranties regarding the Company’s stock or units, operations or financial condition.

3. Other Activities. Except as provided in this Agreement or approved by the Compensation Committee, or its designee, as applicable, in writing, the Executive agrees not to: (a) engage in other operating business activities independent of the Company; (b) serve as a general partner, officer, executive, director or member of any corporation, partnership, company or firm; or (c) directly or indirectly invest, participate or engage in the Oil and Gas Business. For purposes of this Agreement the term “Oil and Gas Business” means: (i) producing oil and gas; (ii) drilling, owning or operating an interest in oil and gas leases or wells; (iii) providing material or services to the Oil and Gas Business; (iv) refining, processing or marketing oil or gas; or (v) owning an interest in or assisting any corporation, partnership, company, entity or person in any of the foregoing. The foregoing will not prohibit: (v) ownership of publicly traded securities; (w) ownership of royalty interests where the Executive owns or previously owned the surface of the land covered in whole or in part by the royalty interest and the ownership of the royalty interest is incidental to the ownership of such surface estate; (x) ownership of royalty interests, overriding royalty interests, working interests or other interests in oil and gas owned prior to the Executive’s date of first employment with the company and disclosed to the

Company in writing; (y) ownership of royalty interests, overriding royalty interests, working interests or other interests in oil and gas acquired by the Executive through a bona fide gift or inheritance subject to disclosure by Executive to the Company in writing; or (z) service as an officer or director of a not-for-profit organization. If the Executive serves as a director or officer of a not-for-profit organization, the Executive shall disclose the name of the organization and their involvement in an annual disclosure statement, the form of which shall be provided by the Company.

4. Executive’s Compensation. The Company agrees to compensate the Executive as follows:

4.1 Base Salary. A base salary (the “Base Salary”), at the initial annual rate of not less than Six Hundred Thousand Dollars ($600,000.00) will be paid to the Executive in regular installments in accordance with the Company’s designated payroll schedule.

4.2 Bonus. The Company will pay to the Executive the remainder of the guaranteed third year annual bonus compensation of not less than Two Hundred Twenty-Five Thousand Dollars ($225,000.00), payable not later than January 31, 2012. Bonus compensation shall be paid to the Executive by separate check or wire transfer apart from Executive’s Base Salary described above in Paragraph 4.1, net of standard, appropriate employment-related deductions (including federal income tax at the applicable Supplemental Tax Withholding Rate), under the appropriate Internal Revenue Service (“IRS”) guidelines and applicable state tax rules. In order to be entitled to the bonus compensation set forth herein and any future bonuses, the Executive must be an active full-time employee of the Company on the bonus payment date(s) selected by the Company. The Executive recognizes and acknowledges that except as provided above, the award of bonuses is not guaranteed or promised in any way. Additionally, in the event the Executive resigns employment, the Executive shall not be eligible for any bonus compensation that may have otherwise been payable after such initial notice of resignation.

4.3 Equity Compensation. In addition to the compensation set forth in Paragraphs 4.1 and 4.2 of this Agreement, the Executive will be granted an award of not less than Eight Hundred Thirty Thousand Dollars ($830,000.00) of Chesapeake Energy Corporation (“CHK”) restricted stock not later than the first business day of January 2012. The corresponding number of shares to be awarded will be calculated using the closing stock price as of the grant date of the award. Vesting for all equity will occur over a four year period (at 25% per year in arrears) under the terms of CHK’s equity compensation plans. Such equity compensation shall be awarded on the regularly scheduled dates selected by the Company for the granting of such equity compensation to other executive employees. In order to be entitled to the equity compensation set forth herein, the Executive must be an active full-time employee of the Company on the equity grant dates. Further, the

terms and provisions of the Equity Compensation Plans control and direct the award of CHK restricted stock and any conflict between this Agreement and the Equity Compensation Plans will be resolved in favor of the terms and provisions of the Equity Compensation Plans. Chesapeake Midstream Management, L.L.C. (“CMM”) reserves the right to grant restricted units of Chesapeake Midstream Partners, L.P. (“MLP restricted units”) in substitution for any CHK restricted stock award that the Executive may be entitled to receive under this Agreement. If CMM grants such substitute MLP restricted units to the Executive, the number of MLP restricted units the Executive will be granted will be the same number as the number of shares of CHK restricted stock that are being substituted on the date of the grant or, in CMM’s discretion, the number of MLP restricted units will have a substantially equivalent fair market value, determined on the date of the award, as the number of shares of CHK restricted stock that are being substituted on that date.

4.4 Benefits. The Company will provide the Executive such retirement benefits, reimbursement of reasonable expenditures for dues, travel and entertainment and such other benefits as are customarily provided to similarly situated executives of the Company and as are set forth in and governed by the Company’s Employment Policies Manual. The Company will also provide the Executive the opportunity to apply for coverage under the Company’s medical, life and disability plans, if any. If the Executive is accepted for coverage under such plans, the Company will make such coverage available to the Executive on the same terms as is customarily provided by the Company to the plan participants as modified from time to time. The Executive is subject to all of the terms and provisions of the Company’s benefit plans or policies. The following specific benefits will also be provided to the Executive at the expense of the Company:

4.4.1 PTO. The Executive will be entitled to take one hundred seventy-six (176) hours of Paid Time Off (“PTO”) annually, calculated from the Executive’s anniversary date, during the term of this Agreement. No additional compensation will be paid for failure to take PTO.

4.4.2 Membership Dues. The Company will reimburse the Executive for: (a) the monthly dues necessary to maintain a full membership in a club in the Oklahoma City area selected by the Executive in an amount not to exceed Seven Hundred Fifty Dollars ($750.00) per month; and (b) the reasonable cost of any approved business entertainment at such club. Such reimbursement shall be made within thirty (30) days of the date such costs are incurred and submitted for reimbursement. All other costs, including, without implied limitation, any initiation costs, initial membership costs, personal use and business entertainment unrelated to the Company will be the sole obligation of the Executive and the Company will have no liability with respect to such amounts.

4.5 Change of Control Payment. If, during the term of this Agreement, there is a Change of Control (as hereafter defined) the Executive will be entitled to a lump sum payment (the “Change of Control Payment”) within thirty (30) days of the effective date of the Change of Control (in addition to any other amounts payable to the Executive under this Agreement or otherwise) in an amount equal to two hundred percent (200%) of: (a) the Executive’s then current Base Salary under paragraph 4.1 of this Agreement and (b) the actual bonuses paid to the Executive during the twelve (12) calendar months preceding the Change of Control under paragraph 4.2 of this Agreement or its predecessor. Additionally, upon the occurrence of such a Change of Control all Equity Compensation granted to the Executive under Section 4.3 of this Agreement will be immediately vested. For the purpose of this Agreement, a “Change of Control” means the occurrence of any of the following:

(a) the acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of thirty percent (30%) or more of either (i) the then outstanding shares of the Company’s common stock (the “Outstanding CHK Common Stock”) or (ii) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding CHK Voting Securities”). For purposes of this paragraph, the following acquisitions by a Person will not constitute a Change of Control: (i) any acquisition directly from the Company; (ii) any acquisition by the Company; (iii) any acquisition by or sponsored by Mr. Aubrey K. McClendon; (iv) any acquisition by any Executive benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company; or (v) any acquisition by any corporation pursuant to a transaction which complies with clauses (i), (ii) and (iii) of paragraph (c) below;

(b) the individuals who, as of June 11, 2010, constitute the Board of Directors (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board of Directors. Any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company’s shareholders, is approved by a vote of at least a majority of the directors then comprising the Incumbent Board will be considered a member of the Incumbent Board as of the date hereof, but any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Incumbent Board will not be deemed a member of the Incumbent Board as of the date hereof;

(c) the consummation of a reorganization, merger, consolidation or sale or other disposition of all or substantially all of the assets of the Company (a “Business Combination”), unless following such Business Combination: (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding CHK Common Stock and Outstanding CHK Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than sixty percent (60%) of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination of the Outstanding CHK Common Stock and Outstanding CHK Voting Securities, as the case may be, (ii) no Person (excluding any corporation resulting from such Business Combination or any Executive benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, thirty percent (30%) or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination and (iii) at least a majority of the members of the Board of Directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Incumbent Board, providing for such Business Combination; or,

(d) the approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.

4.6 Indemnity. The Company will declare GP as an insured entity under its Directors and Officers insurance policies to extend the coverage of such policies to Executive’s performance of duties for GP.

5. Term. The employment relationship evidenced by this Agreement is an “at will” employment relationship and the Company reserves the right to terminate the Executive at any time with or without cause as provided herein. In the absence of such termination, this Agreement will end on November 10, 2014 (the “Expiration Date”).

6. Termination. This Agreement will continue in effect until the expiration of the term stated in paragraph 5 of this Agreement unless earlier terminated pursuant to this paragraph 6.

6.1 Termination by Company. The Company will have the following rights to terminate this Agreement:

6.1.1 Termination without Cause. The Company may terminate this Agreement without Cause at any time by the service of written notice of termination to the Executive specifying an effective date of such termination not sooner than thirty (30) business days after the date of such notice (the “Termination Date”). In the event of elimination of the Executive’s job position or reduction in duties and/or reassignment of the Executive to a new position of less authority or reduction in Base Salary (collectively referred to as the “Good Reason Conditions”) the Executive may terminate this Agreement if the Executive provides notice to the Company within ninety (90) days of the initial existence of the Good Reason Condition and a thirty (30) day period for the Company to cure the Good Reason Condition. Provided, however, that none of the following shall constitute a Good Reason Condition: a reassignment of Executive to provide services for GP, the sharing of Executive’s services with GP, or any other action or inaction by the Company in furtherance of its obligations under that certain Amended and Restated Shared Services Agreement between the Company, GP, and the other parties hereto or, that certain Shared Services Agreement dated as of September 30, 2009. If the Company fails to cure the Good Reason Condition within the thirty (30) day cure period, the Executive may terminate this Agreement and it will be deemed to be a termination without Cause. In the event the Executive is terminated without Cause, the Executive will receive as termination compensation within thirty (30) days of the Termination Date: (a) fifty-two (52) weeks of Base Salary in a lump sum payment; (b) all Equity Compensation granted to Executive under Section 4.3 of this Agreement and any Supplemental Matching Contributions to the Chesapeake Energy Corporation Amended and Restated Deferred Compensation Plan (the “401(k) Make-Up Plan”) shall be immediately vested; and (c) payment of any PTO pay accrued through the Termination Date. The right to the foregoing termination compensation under clauses (a) and (b) above is subject to the Executive’s execution of the Company’s severance agreement which will operate as a release of all legally waivable claims against the Company and the Executive’s compliance with all of the provisions of this Agreement, including all post-employment obligations.

6.1.2 Termination for Cause. The Company may terminate the employment of the Executive hereunder at any time for Cause (as hereinafter defined) (such a termination being referred to in this Agreement as a “Termination For Cause”) by giving the Executive written notice of such termination, which shall take effect immediately upon the giving of such notice to the Executive. As used in this Agreement, “Cause” means (a) the Executive’s breach or threatened breach of this Agreement; (b) the Executive’s neglect of duties or failure to act, other than by reason of disability or death; (c) the misappropriation, fraudulent conduct, or acts of workplace dishonesty by the Executive with respect to the assets or operations of the Company or any of its subsidiaries or affiliated companies; (d) the Executive’s failure to comply with directives from superiors or written company policies; (e) the Executive’s personal misconduct which injures the Company and/or reflects poorly on the Company’s reputation; (f) the Executive’s failure to perform Executive’s duties; or (g) the conviction of the Executive for, or a plea of guilty or no contest to, a felony or any crime involving moral turpitude. In the event this Agreement is terminated for Cause, the Company will not have any obligation to provide any further payments or benefits to the Executive after the Termination Date other than any PTO pay accrued through the Termination Date.

6.2 Termination by Executive. The Executive may voluntarily terminate this Agreement with or without cause by the service of written notice of such termination to the Company specifying a Termination Date no sooner than thirty (30) days after the date of such notice. The Company reserves the right to end the employment relationship at any time after the notice date and to pay Executive through the notice date. If this Agreement is terminated by the Executive in accordance with this paragraph, the obligations of the parties will be controlled by paragraphs 6.3 and 6.6 of this Agreement.

6.3 Retirement by Executive. In the event the Executive is fifty- five (55) years or older and terminates this Agreement under paragraph 6.2 of this Agreement, the Executive will be (a) eligible for accelerated vesting of the unvested Equity Compensation awarded by the Company with the exception of any Equity Compensation issued to the Executive under the 2006 Long Term Stock Incentive Program award; and (b) eligible for accelerated vesting of the unvested Supplemental Matching Contributions to the 401(k) Make-Up Plan. The accelerated vesting under clauses (a) and (b) of this paragraph will be in accordance with the retirement matrix (the “Retirement Matrix”) attached to this Agreement.

6.4 Incapacity of Executive. If the Executive suffers from a physical or mental condition which in the reasonable judgment of the Company’s management prevents the Executive in whole or in part from performing the duties specified herein for a period of three (3) consecutive months, the Executive may be terminated. Although the termination may be deemed as a termination for Cause, the Executive will be entitled to receive within thirty (30) days of the Date of Termination: (a) a payment of twenty-six (26) weeks of Base Salary in a lump sum; (b) all Equity Compensation granted to the Executive under Section 4.3 of this Agreement and any Supplemental Matching Contributions to the 401(k) Make-Up Plan shall be immediately vested; and (c) payment of any PTO pay accrued through the Termination Date. Notwithstanding the foregoing, the amount payable under clause (a) above will be reduced by any benefits payable under any disability plans provided by the Company. The right to the foregoing compensation due under clauses (a) and (b) above is subject to the execution by the Executive or the Executive’s legal representative of the Company’s severance agreement which will operate as a release of all legally waivable claims against the Company. In applying this section, the Company will comply with any applicable legal requirements, including the Americans with Disabilities Act.

6.5 Death of Executive. If the Executive dies during the term of this Agreement, the Company may thereafter terminate this Agreement without compensation except the Company will: (a) pay fifty-two (52) weeks of Base Salary in a single lump sum payment within ninety (90) days of the date of the Executive’s death; (b) immediately vest all Equity Compensation granted to the Executive under Section 4.3 of this Agreement and any Supplemental Matching Contributions to the 401(k) Make-Up Plan; and (c) pay any PTO pay accrued through the Termination Date. Amounts payable under this Section 6.5 shall be paid to the beneficiary designated on the Company’s universal beneficiary designation form in effect on the date of the Executive’s death. If the Executive fails to designate a beneficiary or if such designation is ineffective, in whole or in part, any payment that would otherwise have been paid under this Section 6.5 shall be paid to the Executive’s estate. The right to the foregoing compensation due under clauses (a) and (b) above is subject to the execution by the beneficiary, or as applicable, the administrator of the Executive’s estate of the Company’s severance agreement which will operate as a release of all legally waivable claims against the Company.

6.6 Effect of Termination. The termination of this Agreement will terminate all obligations of the Executive to render services on behalf of the Company from and after the Termination Date, provided that the Executive will maintain the confidentiality of all information acquired by the Executive during the term of Executive’s employment in accordance with paragraph 7 of this Agreement and the Executive shall comply with all other post employment requirements including paragraphs 7, 8, 9, 10, 11, 12, 13 and

14. Executive hereby acknowledges and agrees that for purposes of Executive’s post-employment obligations contained in paragraphs 7, 8, 9, 10, 11, 12 and 13, the term ‘Company’ shall include GP, the MLP and its subsidiaries (the “MLP Group”). Except as otherwise provided in paragraphs 4.5 and 6 of this Agreement and payment of any PTO pay accrued through the Termination Date, no accrued bonus, severance pay or other form of compensation will be payable by the Company to the Executive by reason of the termination of this Agreement. All keys, entry cards, credit cards, files, records, financial information, furniture, furnishings, equipment, supplies and other items relating to the Company in the Executive’s possession will remain the property of the Company. The Executive will have the right to retain and remove all personal property and effects which are owned by the Executive and located in the offices of the Company at a time determined by the Company. All such personal items will be removed from such offices no later than two (2) days after the Termination Date, and the Company is hereby authorized to discard any items remaining and to reassign the Executive’s office space after such date. Prior to the Termination Date, the Executive will render such services to the Company as might be reasonably required to provide for the orderly termination of the Executive’s employment. Notwithstanding the foregoing and without discharging any obligations to pay compensation to the Executive under this Agreement, after notice of the Termination, the Company may request that the Executive not provide any other services to the Company and not enter the Company’s premises before or after the Termination Date. In the event that the Executive separates employment with the Company, Executive hereby grants consent to notification by the Company to Executive’s new employer about Executive’s rights and obligations under this Agreement. Upon such termination of employment, the Executive further agrees to acknowledge compliance with this Agreement in a form reasonably provided by the Company.

7. Confidentiality. The Executive recognizes that the nature of the Executive’s services are such that the Executive will have access to information which constitutes trade secrets, is of a confidential nature, is of great value to the Company and/or is the foundation on which the business of the Company is predicated. The Executive also acknowledges that, during the course of employment, the Executive may have personal contact and conduct business with the customers, suppliers and accounts of the Employer. The Executive agrees not to disclose to any person other than authorized Executives of the Company or the Company’s legal counsel nor use for any purpose, other than the performance of this Agreement, any confidential information (“Confidential Information”). Confidential Information includes data or material (regardless of form) which is: (a) a trade secret (a trade secret shall include any formula, pattern, device or compilation of information used by the Employer in its business); (b) provided, disclosed or delivered to Executive by the Company, any officer, director, Executive, agent, attorney, accountant, consultant, or other person or entity employed by the Company in any capacity, any customer, borrower or business

associate of the Company or any public authority having jurisdiction over the Company of any business activity conducted by the Company; or (c) produced, developed, obtained or prepared by or on behalf of Executive or the Company (whether or not such information was developed in the performance of this Agreement) with respect to the Company or any assets oil and gas prospects, business activities, officers, directors, Executives, borrowers or customers of the foregoing. The Executive acknowledges that Executive will obtain unique benefits from employment and the provisions contained in this Agreement are reasonably necessary to protect the Employer’s legitimate business interests. On request by the Company, the Company will be entitled to the return of any Confidential Information in the possession of the Executive. The Executive also agrees that the provisions of this paragraph 7 will survive the termination, expiration or cancellation of this Agreement for a period of three (3) years. The Executive will deliver to the Company all originals and copies of the documents or materials containing Confidential Information. For purposes of paragraphs 7, 8, 9, 10 and 13 of this Agreement, the Company expressly includes any of the Company’s affiliated corporations, partnerships or entities.

8. Non-Competition. For a period of six (6) months after the Executive is no longer employed by the Company for any reason, the Executive will not acquire, attempt to acquire or aid another in the acquisition or attempted acquisition of an interest in oil and gas assets, oil and gas production, oil and gas leases, mineral interests, oil and gas wells or other such oil and gas exploration, development or production activities within any spacing unit in which the Company owns an oil and gas interest on the date of the resignation or termination of the Executive. Notwithstanding the foregoing, this Section 8 shall not preclude or restrict Executive from performing services for GP and the MLP Group, or owning an interest in the MLP (whether prior to, during, or after his employment with the Company), and neither the performance of such services nor the ownership of such interest shall violate the terms of this Agreement.

9. Non-Solicitation. The Executive agrees that during his/her employment hereunder, and for the one (1) year period immediately following the separation of employment for any reason, the Executive shall not solicit or contact any established client or customer of the Company with a view to inducing or encouraging such established client or customer to discontinue or curtail any business relationship with the Company. The Executive further agrees that the Executive will not request or advise any established clients, customers or suppliers of the Company to withdraw, curtail or cancel its business with the Company. Notwithstanding the foregoing, this Section 9 shall not preclude or restrict Executive from engaging in any such activities in connection with his performance of services for GP and the MLP Group or undertaken for the benefit of GP or the MLP Group (whether prior to, during, or after his employment with the Company), and the Executive’s engaging in such activities shall not violate the terms of this Agreement.

10. Non-Solicitation of Employees. The Executive covenants that during the term of employment and for the one (1) year period immediately following the separation of employment for any reason, Executive will neither directly nor indirectly induce nor attempt to induce any Executive or Employee of the Company to terminate his or her employment to go to work for any other Company. Notwithstanding the foregoing, this Section 10 shall not preclude or restrict Executive from engaging, with the Company’s consent, in any such activities in connection with his performance of services for GP or the MLP Group or undertaken for the benefit of GP or the MLP Group (whether prior to, during, or after his employment with the Company), and the Executive’s engaging in such activities with the Company’s consent shall not violate the terms of this Agreement.

11. Reasonableness. The Company and Executive have attempted to specify a reasonable period of time and reasonable restrictions to which this Agreement shall apply. The Company and Executive agree that if a court or administrative body should subsequently determine that the terms of this Agreement are greater than reasonably necessary to protect the Company’s interest, the Company agrees to waive those terms which are found by a court or administrative body to be greater than reasonably necessary to protect the Company’s interest and to request that the court or administrative body reform this Agreement specifying a reasonable period of time and such other reasonable restrictions as the court or administrative body deems necessary.

12. Equitable Relief. The Executive acknowledges that the services to be rendered by Executive are of a special, unique, unusual, extraordinary, and intellectual character, which gives them a peculiar value, and the loss of which cannot reasonably or adequately be compensated in damages in an action at law; and that a breach by the Executive of any of the provisions contained in this Agreement will cause the Company irreparable injury and damage. The Executive further acknowledges that the Executive possesses unique skills, knowledge and ability and that any material breach of the provisions of this Agreement would be extremely detrimental to the Company. By reason thereof, the Executive agrees that the Company shall be entitled, in addition to any other remedies it may have under this Agreement or otherwise, to injunctive and other equitable relief to prevent or curtail any breach of this Agreement by him/her.

13. Proprietary Matters. The Executive expressly understands and agrees that any and all improvements, inventions, discoveries, processes, know-how or intellectual property that are generated or conceived by the Executive during the term of this Agreement, whether generated or conceived during the Executive’s regular working hours or otherwise, will be the sole and exclusive property of the Company. Whenever requested by the Company (either during the term of this Agreement or thereafter), the Executive will assign or execute any and all applications, assignments and or other instruments and do all things which the Company deems necessary or appropriate in order to permit the Company to: (a) assign and convey or otherwise make available to the Company the sole and exclusive right, title, and interest in and to said improvements, inventions, discoveries, processes, know-how, applications, patents, copyrights, trade names or trademarks; or (b) apply for, obtain, maintain, enforce and defend patents, copyrights, trade names, or

trademarks of the United States or of foreign countries for said improvements, inventions, discoveries, processes or know-how. However, the improvements, inventions, discoveries, processes or know-how generated or conceived by the Executive and referred to above (except as they may be included in the patents, copyrights or registered trade names or trademarks of the Company, or corporations, partnerships or other entities which may be affiliated with the Company) shall not be exclusive property of the Company at any time after having been disclosed or revealed or have otherwise become available to the public or to a third party on a non-confidential basis other than by a breach of this Agreement, or after they have been independently developed or discussed without a breach of this Agreement by a third party who has no obligation to the Company or its affiliates. The foregoing will not prohibit any activities which are expressly permitted by the last sentence of paragraph 3 of this Agreement during the term of this Agreement.

14. Arbitration. Any disputes, claims or controversy’s between the Employer and Executive including, but not limited to those arising out of or related to this Agreement or out of the parties’ employment relationship, shall be settled by arbitration as provided herein. This agreement shall survive the termination or rescission of this Agreement. All arbitration shall be in accordance with Rules of the American Arbitration Association, including discovery, and shall be undertaken pursuant to the Federal Arbitration Act. Arbitration will be held in Oklahoma City, Oklahoma unless the parties mutually agree to another location. The decision of the arbitrator will be enforceable in any court of competent jurisdiction. The parties, however, agree that the Employer shall be entitled to obtain injunctive or other equitable relief to enforce the provisions of this Agreement in a court of competent jurisdiction. The parties further agree that this arbitration provision is not only applicable to the Company but its affiliates, officers, directors, employees and related parties.

15. Miscellaneous. The parties further agree as follows:

15.1 Time. Time is of the essence of each provision of this Agreement.

15.2 Notices. Any notice, payment, demand or communication required or permitted to be given by any provision of this Agreement will be in writing and will be deemed to have been given when delivered personally or by express mail to the party designated to receive such notice, or on the date following the day sent by overnight courier, or on the third (3^rd) business day after the same is sent by certified mail, postage and charges prepaid, directed to the following address or to such other or additional addresses as any party might designate by written notice to the other party:

To the Company:	Chesapeake Energy Corporation
	6100 N. Western Avenue
	Oklahoma City, OK 73118
	Attn: Aubrey K. McClendon
To the Executive:	John M. Stice
	[home address]

15.3 Assignment. Neither this Agreement nor any of the parties’ rights or obligations hereunder can be transferred or assigned without the prior written consent of the other parties to this Agreement; provided, however, the Company may assign this Agreement to any wholly owned affiliate or subsidiary of Chesapeake Energy Corporation without Executive’s consent as well as to any purchaser of the Company.

15.4 Construction. If any provision of this Agreement or the application thereof to any person or circumstances is determined, to any extent, to be invalid or unenforceable, the remainder of this Agreement, or the application of such provision to persons or circumstances other than those as to which the same is held invalid or unenforceable, will not be affected thereby, and each term and provision of this Agreement will be valid and enforceable to the fullest extent permitted by law. Except as provided for in paragraph 14, this Agreement is intended to be interpreted, construed and enforced in accordance with the laws of the State of Oklahoma.

15.5 Entire Agreement. This Agreement, any documents executed in connection with this Agreement, any documents specifically referred to in this Agreement and the Employment Policies Manual constitute the entire agreement between the parties hereto with respect to the subject matter herein contained, and no modification hereof will be effective unless made by a supplemental written agreement executed by all of the parties hereto.

15.6 Binding Effect. This Agreement will be binding on the parties and their respective successors, legal representatives and permitted assigns. In the event of a merger, consolidation, combination, dissolution or liquidation of the Company, the performance of this Agreement will be assumed by any entity which succeeds to or is transferred the business of the Company as a result thereof, and the Executive waives the consent requirement of paragraph 15.3 to effect such assumption.

15.7 Supersession. This Agreement supersedes and replaces any prior employment agreements including the Prior Agreement. On execution of this Agreement by the Company and the Executive, the relationship between the Company and the Executive will be bound by the terms of this Agreement, any documents executed in connection with this Agreement, any documents specifically referred to in this Agreement and the Employment Policies Manual. In the event of a conflict between the Employment Policies Manual and this Agreement, this Agreement will control in all respects.

15.8 Third-Party Beneficiary. The Company’s affiliated entities and partnerships are beneficiaries of all terms and provisions of this Agreement and entitled to all rights hereunder. The Executive and the Company expressly intend that, with respect to Sections 2 (Executive’s Duties), 2.1 (Specific Duties), 7, 8, 9, 10, 11, 12 and 13, GP shall be an intended third party beneficiary and shall have standing to enforce such provisions as if it were a party hereto.

15.9 Section 409A. This Agreement is intended to comply with Internal Revenue Code Section 409A and related U.S. Treasury regulations or pronouncements (“Section 409A”) and any ambiguous provision will be construed in a manner that is compliant with or exempt from the application of Section 409A. Notwithstanding any provision to the contrary in this Agreement, if Executive is deemed on his Termination Date to be a “specified employee” within the meaning of that term under Section 409A(a)(2)(B) of the Internal Revenue Code, then the payments and benefits under this Agreement that are subject to Section 409A and paid by reason of a termination of employment shall be made or provided (subject to the last sentence hereof) on the later of (a) the payment date set forth in this Agreement or (b) the date that is the earliest of (i) the expiration of the six-month period measured from the date of the Executive’s Termination of employment or (ii) the date of the Executive’s death (the “Delay Period”). Payments subject to the Delay Period shall be paid to the Executive without interest for such delay in payment.

15.10 Scope of Release. The Executive agrees that any release of claims provided by the Executive to the Company shall include GP, the MLP Group and their respective related entities and individuals as releasees to the same extent that the Company and the Company’s related entities and individuals are included as releasees.

IN WITNESS WHEREOF, the undersigned have executed this Agreement effective the date first above written.

CHESAPEAKE ENERGY CORPORATION, an Oklahoma corporation.
By:	/s/ Aubrey K. McClendon
	Aubrey K. McClendon, Chief Executive Officer
	(the “Company”)
By:	/s/ John M. Stice
	John M. Stice, Individually
	(the “Executive”)

RETIREMENT MATRIX

Senior Vice President
Service Yrs	<55			55-59			60-64			>= 65
0 - 5		0	%		0	%		0	%		0	%
5 - 10		0	%		60	%		80	%		100	%
10 - 15		0	%		80	%		100	%		100	%
15 +		0	%		100	%		100	%		100	%

EX-10.16.1

Exhibit 10.16.1

AMENDMENT TO EMPLOYMENT AGREEMENT

This Amendment to Employment Agreement (the “Amendment”) is effective December 22, 2011 (the “Effective Date”), by and between Chesapeake Energy Corporation, an Oklahoma corporation (the “Company”), and JOHN M. STICE, an individual (the “Executive”). The Company and the Executive are referred to collectively in this Amendment as the “Parties.”

WHEREAS, the Parties have entered into an employment agreement (the “Employment Agreement”); and

WHEREAS, the Parties desire to amend the Employment Agreement.

NOW, THEREFORE, in consideration of the promises and mutual agreements herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

1. All capitalized terms used in this Amendment and not otherwise defined shall have the same meaning in this Amendment as in the Employment Agreement.

2. The Employment Agreement is amended to delete Subparagraph 4.4.2 in its entirety.

3. Except as otherwise amended by this Amendment, the remaining terms of the Employment Agreement remain in full force and effect.

IN WITNESS WHEREOF, the Parties have executed this Amendment to Employment Agreement as of the Effective Date.

Company:	Chesapeake Energy Corporation
	By:	/s/ Aubrey K. McClendon
		Aubrey K. McClendon
		Chief Executive Officer
Executive:		/s/ John M. Stice
		John M. Stice

EX-12.1

Exhibit 12.1

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Year Ended December 31, 2011			Year Ended December 31, 2010			Three Months Ended December 31, 2009			Predecessor
										Nine Months Ended September 30, 2009			Year Ended December 31, 2008		Year Ended December 31, 2007
	($ in thousands)
Earnings:
Income before income taxes		$197,626		$	197,658		$	51,331		$	(11,033	)	$	104,008	$	82,957
Add:
Fixed charges		44,648			27,047			6,095			21,619			19,016		8,766
Amortization of capitalized interest		667			147			—			—			—		—
Less:
Capitalized interest		(9,541	)		(2,631	)		(257	)		(3,782	)		—		—
Earnings		$233,400		$	222,221		$	57,169		$	6,804		$	123,024	$	91,723
Fixed charges:
Interest expensed and capitalized		$19,772		$	5,490		$	877		$	4,129		$	1,871	$	—
Amortization of debt expense		4,660			4,876			1,321			1,427			513		—
Interest component of rent expense		20,216			16,681			3,897			16,063			16,632		8,766
Fixed charges		$44,648		$	27,047		$	6,095		$	21,619		$	19,016	$	8,766
Ratio of earnings to fixed charges		5.2x			8.2x			9.4x			—			6.5x		10.5x

These ratios were computed by dividing earnings by fixed charges. For this purpose, earnings include pre-tax income, plus fixed charges to the extent they affect current year earnings, amortization of capitalized interest, then subtracting interest capitalized during the year. Fixed charges include interest expensed and capitalized, amortized premiums, discounts and capitalized expenses related to indebtedness, and estimates of interest within rental expenses.

EX-21.1

Exhibit 21.1

SUBSIDIARIES

OF

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

Delaware Limited Partnership

	State of Formation
Appalachia Midstream Services, L.L.C.	Oklahoma
Bluestem Gas Services, L.L.C.	Oklahoma
Chesapeake MLP Operating, L.L.C.	Delaware
Chesapeake Midstream Gas Services, L.L.C.	Oklahoma
CHKM Finance Corp.	Delaware
Magnolia Midstream Gas Services, L.L.C.	Oklahoma
Oklahoma Midstream Gas Services, L.L.C.	Oklahoma
Ponder Midstream Gas Services, L.L.C.	Delaware
Texas Midstream Gas Services, L.L.C.	Oklahoma

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form’s S-3 (No. 333-175982), and S-8 (No. 333-169338) of Chesapeake Midstream Partners, L.P. of our reports dated February 29, 2012 relating to the financial statements and the effectiveness of internal control over financial reporting, which appear in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 29, 2012

EX-31.1

Exhibit 31.1

CERTIFICATION

I, J. Mike Stice, certify that:

1. I have reviewed this Annual Report on Form 10-K of Chesapeake Midstream Partners, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedure, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 29, 2012	/s/ J. MIKE STICE
	J. Mike Stice
	Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, David C. Shiels, certify that:

1. I have reviewed this Annual Report on Form 10-K of Chesapeake Midstream Partners, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedure, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 29, 2012	/s/ DAVID C. SHIELS
	David C. Shiels
	Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Chesapeake Midstream Partners, L.P. (the “Partnership”) on Form 10-K for the period ended December 31, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, J. Mike Stice, Chief Executive Officer of the Partnership, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

/s/ J. MIKE STICE

J. Mike Stice

Chief Executive Officer

Date: February 29, 2012

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Chesapeake Midstream Partners, L.P. (the “Partnership”) on Form 10-K for the period ended December 31, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David C. Shiels, Chief Financial Officer of the Partnership, certify, pursuant to 18 U.S.C.§ 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

/s/ DAVID C. SHIELS

David C. Shiels

Chief Financial Officer

Date: February 29, 2012

XML

Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

2. Summary of Significant Accounting Policies

Use of estimates.  The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. Significant estimates include: (1) estimated useful lives of assets, which impacts depreciation and amortization; (2) accruals related to revenues, expenses and capital costs; (3) liability and contingency accruals; and (4) cost allocations as described in Note 5. Although management believes these estimates are reasonable, actual results could differ from the Partnership's estimates.

Cash and cash equivalents.  For purposes of the consolidated financial statements, investments in all highly liquid instruments with original maturities of three months or less at date of purchase are considered to be cash equivalents. The Partnership had approximately $22 thousand and $17.8 million of cash and cash equivalents as of December 31, 2011 and 2010, respectively. Book overdrafts are checks that have been issued before the end of the period, but not presented to the bank for payment before the end of the period. At December 31, 2011 and 2010, book overdrafts of $8.5 million and $4.0 million, respectively, were included in accounts payable.

Accounts receivable.  The majority of accounts receivable relate to gathering and treating activities. Accounts receivable included in the balance sheets are reflected net of an allowance for doubtful accounts, if warranted. At December 31, 2011, the Partnership had an allowance for doubtful accounts of $0.4 million. No allowance for doubtful accounts was necessary at December 31, 2010.

Property, plant and equipment.  Property, plant and equipment are recorded at cost. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. As assets are disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in operating expenses in the statements of operations. The predecessor recorded a $44.6 million loss on the sale of certain non-core, non-strategic gathering systems during the period ended September 30, 2009.

Certain of the gathering systems of the Partnership are subject to an agreement with a subsidiary of Chesapeake, which provides the Partnership rights and obligations equivalent to a capital lease. Under the terms of the agreement, the Partnership has rights to the associated capital assets for as long as the assets are in operation. Specifically, the Partnership will pay all costs associated with the related gathering systems, including all capital costs, operating costs and direct and indirect overhead costs. In exchange for paying such costs and for the services it provides pursuant to this agreement, the Partnership receives revenues derived from operation of the gathering systems. At December 31, 2011 and 2010, approximately $124.5 million and $122.5 million ($105.0 million and $109.2 million net of accumulated depreciation) of the Partnership's gathering system assets were held under such agreement, respectively. Payments for capital costs under the agreement are made as the associated capital assets are constructed and, accordingly, the Partnership has no capital lease obligation liability associated with the assets held under this agreement as of December 31, 2011.

Depreciation is calculated using the straight-line method, based on the assets' estimated useful lives. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets.

Impairment of long-lived assets.  Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount that the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risks associated with achieving the underlying cash flows.

During 2009, the predecessor recognized an impairment charge of $86.2 million associated with certain mid-continent gathering systems. The impairment was the result of a reduction in the future expected throughput volumes on these systems by Chesapeake based on its revised future development plans of the underlying oil and gas properties, as well as the impact of the terms of the new gas gathering agreements entered into with Chesapeake in conjunction with the formation of the joint venture on September 30, 2009. These systems were subsequently contributed to the Partnership upon its formation. Additionally, the predecessor also expensed $4 million of debt issuance costs as a result of the amendment of the credit facility (See Note 12) resulting in total impairments of $90.2 million in 2009.

Equity Method Investments.  The equity method of accounting is used to account for the Partnership's interest in Appalachia Midstream, which was acquired on December 29, 2011. Through the acquisition of Appalachia Midstream, the Partnership operates 100 percent of and owns an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 231 miles of gas gathering pipeline in the Marcellus Shale. The remaining 53 percent interest in these assets is owned primarily by Statoil, Anadarko, Epsilon and Mitsui. See Note 1 – Description of Business and Basis of Presentation for more information on the acquisition.

Asset retirement obligations.  Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at the Partnership's fair value measured using expected discounted future cash outflows of the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Accretion expense is recognized over time as the discounted liability is accreted to the Partnership's expected settlement value. Subsequent to the initial recognition, the liability is adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) and for accretion of the liability due to the passage of time, until the obligation is settled. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the associated asset carrying amount. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, retirement costs and the estimated timing of settling asset retirement obligations.

Fair value.  The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

Level 1—inputs represent quoted prices in active markets for identical assets or liabilities.

Level 2—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3—inputs that are not observable from objective sources, such as management's internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management's internally developed present value of future cash flows model that underlies the fair value measurement).

Nonfinancial assets and liabilities initially measured at fair value include third-party business combinations, impaired long-lived assets (asset groups), and initial recognition of asset retirement obligations.

The fair value of debt is the estimated amount the Partnership would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices or average valuations of similar debt instruments at the balance sheet date for those debt instruments for which quoted market prices are not available. See Note 12—Debt and Interest Expense for disclosures regarding the fair value of debt.

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the balance sheet approximates fair value.

Segments.  The Partnership's operations are organized into a single business segment, the assets of which consist of natural gas gathering systems, treating facilities, processing facilities, pipelines and related plant and equipment.

Revenue recognition.  The predecessor's revenues were derived almost exclusively from related parties and were charged under short-term contracts at market sensitive rates. In 2011, the Partnership derived substantially all of its revenues through gas gathering agreements with Chesapeake and Total. Pursuant to the applicable gas gathering agreements, Chesapeake and Total have agreed to minimum volume commitments covering production in the Barnett Shale region for each year through December 31, 2018 and for the six month period ending June 30, 2019, and, solely with respect to Chesapeake, in the Haynesville Shale region for each year through December 31, 2013. In the event either Chesapeake or Total does not meet its minimum volume commitment to the Partnership in the Barnett Shale region or Chesapeake does not meet its minimum volume commitment to the Partnership in the Haynesville Shale region, for any annual period (or six month period with respect to the six months ending June 30, 2019 in the Barnett Shale region) during the minimum volume commitment period, Chesapeake and Total will be obligated to pay a fee equal to the applicable fee for each Mcf by which the applicable party's minimum volume commitment for such year (or six month period with respect to the six months ending June 30, 2019) exceeds the actual volumes gathered from such party's production. The revenue associated with such shortfall fees is recognized in the fourth quarter of each year.

Revenues consist of fees recognized for the gathering, treating and compression of natural gas to major interstate and intrastate pipelines. Revenues are recognized when the service is performed and is based upon non-regulated rates and the related gathering, treating and compression volumes.

Deferred Loan Costs.  External costs incurred in connection with closing the revolving bank credit facilities are capitalized as deferred loan costs and amortized over the life of the related agreement. Amortization is included in interest expense in the statement of operations.

Environmental expenditures.  Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. There are no liabilities reflected in the accompanying financial statements at December 31, 2011 and 2010.

Equity Based Compensation.  Certain employees of Chesapeake have been seconded to the Partnership to provide operating, routine maintenance and other services with respect to the business under the direction, supervision and control of the Partnership's general partner. A number of these employees receive equity-based compensation through Chesapeake's stock-based compensation programs, which consist of restricted stock issued to employees.

The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. However, the Partnership's expense is allocated based on the lesser of the value at grant date or vest date. This value is amortized over the vesting period, which is generally four or five years from the date of grant. To the extent compensation cost relates to employee activities directly involved in gathering or treating operations, such amounts are charged to the Partnership and its predecessor and are reflected as operating expenses. Included in operating expenses is stock-based compensation of $3.8 million, $2.1 million and $0.6 million for the Partnership during the years ended December 31, 2011 and 2010, and three months ended December 31, 2009, respectively, and $5.3 million for its predecessor during the period ended September 30, 2009. To the extent compensation cost relates to employees indirectly involved in gathering or treating operations, such amounts are charged to the Partnership and its predecessor through an overhead allocation and are reflected as general and administrative expenses.

The Chesapeake Midstream Long-Term Incentive Plan ("LTIP") provides for an aggregate of 3,500,000 common units to be awarded to employees, directors and consultants of the Partnership's general partner and its affiliates through various award types, including unit awards, restricted units, phantom units, unit options, unit appreciation rights and other unit-based awards. The LTIP has been designed to promote the interests of the Partnership and its unitholders by strengthening its ability to attract, retain and motivate qualified individuals to serve as employees, directors and consultants.

The following table summarizes LTIP award activity for the year ended December 31, 2011:

	Units			Value per Unit
Restricted units unvested at beginning of period		—		$	—
Granted		288,417			28.50
Vested		(1,773	)		28.78
Forfeited		(13,386	)		28.51
Restricted units unvested at end of period		273,258		$	28.50

Intangible Assets.   Intangible assets are generally amortized on a straight-line basis over their estimated useful lives, unless the assets economic benefits are consumed on an other than straight-line basis. The estimated useful life is the period over which the assets are expected to contribute directly or indirectly to the Partnership's future cash flows. The estimated useful life of the customer relationship acquired with the Springridge gathering system is 15 years.

The Partnership assesses long-lived assets, including property, plant and equipment and intangible assets, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed by comparing the carrying amount of an asset to undiscounted future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured as the amount by which the carrying amounts exceed the fair value of the assets.

Business Combinations.   The Partnership makes various assumptions in developing models for determining the fair values of assets and liabilities associated with business acquisitions. These fair value models, developed with the assistance of outside consultants, apply discounted cash flow approaches to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions to arrive at an economic value for the business acquired. The Partnership then determines the fair value of the tangible assets based on estimates of replacement costs less obsolescence. Identifiable intangible assets acquired consist primarily of customer contracts, customer relationships, trade names, and licenses and permits. The Partnership values customer relationships using a discounted cash flow model.

Income taxes.   Chesapeake and its subsidiaries historically have filed a consolidated federal income tax return and other state returns as required. The predecessor and certain of its subsidiaries, as a partnership or limited liability companies, were not subject to federal income taxes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to the partners of the predecessor and, accordingly, do not result in a provision for income taxes in the accompanying financial statements. As a master limited partnership, the Partnership is a pass-through entity and also not subject to federal income taxes and most state income taxes with the exception of Texas Franchise Tax. For federal and state income tax purposes, all income, expenses, gains, losses and tax credits generate flow through to the owners, and accordingly, do not result in a provision for income taxes.

Income taxes have been provided by the predecessor for its subsidiaries which are subject to federal and state income tax on the basis of their separate company income and deductions. Income taxes have also been provided for the operations of the midstream business prior to its contribution to the predecessor on February 28, 2008, during which period the operations were owned by CEMI and were subject to income taxes. Deferred income taxes have been provided for temporary differences between the book and tax carrying amounts of assets and liabilities held by taxable entities of the predecessor. These differences create taxable or tax deductible amounts for future periods. Current taxes payable of the Partnership related to Texas franchise tax will be paid by the Partnership. Current taxes payable of the predecessor were paid by Chesapeake and have been reflected as contributions from Chesapeake in the accompanying statements of partners' capital/division equity. Chesapeake reimbursed the predecessor for its net operating losses utilized in the completion of Chesapeake's consolidated federal tax returns.

There were no uncertain tax positions at December 31, 2009.

XML

Description Of Business And Basis Of Presentation

12 Months Ended

Dec. 31, 2011

Description Of Business And Basis Of Presentation [Abstract]

Description Of Business And Basis Of Presentation

1. Description of Business and Basis of Presentation

Basis of presentation.  Chesapeake Midstream Partners, L.P., (the "Partnership") a Delaware limited partnership formed in January 2010, is principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. As of December 31, 2011, the Partnership's assets consisted of 187 gathering systems, 5 natural gas treating facilities, 3 gas processing facilities and an ownership interest in 10 additional gas gathering systems. The Partnership's assets are located in Texas, Louisiana, Oklahoma, Kansas, Arkansas, West Virginia and Pennsylvania. The Partnership provides gathering, treating and compression services to Chesapeake Energy Corporation and Total Gas and Power North America, Inc., the Partnership's primary customers, and other producers under long-term, fixed-fee contracts.

For purposes of these financial statements, the "Partnership," when used in a historical context, refers to the financial results of Chesapeake Midstream Partners, L.L.C. from its inception on September 30, 2009 through the closing date of its initial public offering ("IPO") on August 3, 2010 and to Chesapeake Midstream Partners, L.P. and its subsidiaries thereafter. "CMD" or the "predecessor" refers to Chesapeake Midstream Development, L.P. prior to September 30, 2009. "Chesapeake" refers to Chesapeake Energy Corporation and "GIP" refers to Global Infrastructure Partners – A, L.P., and affiliated funds managed by Global Infrastructure Management, LLC, and certain of their respective subsidiaries and affiliates. "Total", when discussing the upstream joint venture with Chesapeake, refers to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A., and when discussing the Partnership's gas gathering agreement and related matters, refers to Total E&P USA, Inc. and Total Gas & Power North America, Inc., a wholly owned subsidiary of Total S.A.

CMD is a Delaware limited partnership formed on February 29, 2008 to own, operate and develop midstream energy assets. Upon formation, gathering and treating assets of Chesapeake Energy Marketing, Inc. ("CEMI"), a wholly owned subsidiary of Chesapeake, were contributed to CMD. CEMI is the sole limited partner of CMD with a 98 percent ownership interest, and Chesapeake Midstream Management L.L.C. ("CMM") is the general partner of CMD with a 2 percent ownership interest. CMM is a wholly owned subsidiary of CEMI.

On September 30, 2009, the predecessor formed a joint venture with Global Infrastructure Partners – A, L.P., and affiliated funds managed by Global Infrastructure Management, LLC, and certain of their respective subsidiaries and affiliates, to own and operate natural gas midstream assets. As part of the transaction, the predecessor contributed certain natural gas gathering and treating assets to a new entity, Chesapeake Midstream Partners, L.L.C. and GIP purchased a 50 percent interest in the newly formed joint venture.

The assets contributed to the joint venture and ultimately the Partnership were substantially all of its predecessor's midstream assets in the Barnett Shale region and certain of its midstream assets in the Anadarko, Arkoma, Delaware and Permian Basins. Subsidiaries of the predecessor continued to operate midstream assets outside of the joint venture. At December 31, 2011, these included natural gas gathering assets primarily in the Haynesville Shale, Marcellus Shale (including other areas in the Appalachian Basin), Utica Shale and the Eagle Ford Shale.

The accompanying consolidated financial statements are presented for current and predecessor periods, which relate to the accounting periods preceding and succeeding the September 30, 2009 joint venture transaction described in Note 1. The current and predecessor periods have been separated by a vertical line on the face of the consolidated financial statements to highlight the fact that the financial information for such periods represents different entities.

The accompanying consolidated financial statements of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP"). To conform to these accounting principles, management makes estimates and assumptions that affect the amounts reported in the consolidated financial statements and the notes thereto. These estimates are evaluated on an ongoing basis, utilizing historical experience and other methods considered reasonable under the particular circumstances. Although these estimates are based on management's best available knowledge at the time, changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates. Effects on the Partnership's business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.

Offerings and acquisitions.

IPO.  On August 3, 2010, the Partnership completed its IPO of 24,437,500 common units (including 3,187,500 common units issued pursuant to the exercise of the underwriters' over-allotment option on August 3, 2010) at a price of $21.00 per unit. The Partnership's common units are listed on the New York Stock Exchange (the "NYSE") under the symbol "CHKM".

The Partnership received gross offering proceeds of approximately $513.2 million less approximately $38.6 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of the contribution agreement, the Partnership distributed the approximate $62.4 million of net proceeds from the exercise of the over-allotment option to GIP on August 3, 2010. Upon completion of the IPO, Chesapeake and GIP conveyed to the Partnership a 100 percent membership interest in Chesapeake MLP Operating, L.L.C., which owned all of its assets since September 2009.

Haynesville acquisition.  On December 21, 2010, the Partnership acquired the Springridge gathering system and related facilities from CMD for $500.0 million. The acquisition was financed with a draw on the Partnership's revolving credit facility of approximately $234.0 million plus approximately $266.0 million of cash on hand. The Springridge gathering system is primarily located in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, the Partnership entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication, annual fee redetermination and a minimum volume commitment. These assets are referred to collectively as the "Springridge assets" and the acquisition is referred to as the "Springridge acquisition."

Marcellus acquisition.  On December 29, 2011, the Partnership acquired from CMD, all of the issued and outstanding common units of Appalachia Midstream Services, L.L.C. ("Appalachia Midstream") for total consideration, which is subject to a customary post-closing working capital adjustment, of $879.3 million, consisting of 9,791,605 common units and $600.0 million in cash that was financed with a draw on the Partnership's revolving credit facility. Through the acquisition of Appalachia Midstream, the Partnership operates 100 percent of and owns an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 231 miles of gas gathering pipeline in the Marcellus Shale. The remaining 53 percent interest in these assets is owned primarily by Statoil ASA ("Statoil"), Anadarko Petroleum Corporation ("Anadarko"), Epsilon Energy Ltd. ("Epsilon"), Mitsui & Co., Ltd. ("Mitsui"). Gross throughput for these assets at December 31, 2011, was just over 1.0 Bcf per day (approximately 470 Mmcf per day net to the Partnership). Appalachia Midstream operates the assets under 15-year fixed fee gathering agreements. The gathering agreements include significant acreage dedications and annual fee redeterminations. In addition, CMD has committed to pay the Partnership quarterly any shortfall between the actual EBITDA from these assets and specified quarterly targets, with the quarterly targets adding to a total of $100 million in 2012 and $150 million in 2013.

Limited partner and general partner units.  The following table summarizes common, subordinated and general partner units issued during the years ended December 31, 2011 and 2010:

	Limited Partner Units				General Partner Interests		Total
	Common		Subordinated
Balance at December 31, 2009		—		—		—		—
Initial public offering and contribution of initial assets		69,076,122		69,076,122		2,819,434		140,971,678
Long-term incentive plan awards		7,143		—		—		7,143
Balance at December 31, 2010		69,083,265		69,076,122		2,819,434		140,978,821
Long-term incentive plan awards		1,773		—		172		1,945
December 2011 equity issuance		9,791,605		—		199,838		9,991,443
Balance at December 31, 2011		78,876,643		69,076,122		3,019,444		150,972,209

Holdings of partnership equity.  At December 31, 2011, Chesapeake held 1,509,722 general partner units representing a 1.0 percent general partner interest in the Partnership, 50 percent of the Partnership IDRs, 33,704,666 common units and 34,538,061 subordinated units. Chesapeake's common and subordinated units represent an aggregate 45.2 percent limited partner interest in the Partnership. The Partnership issued 9,791,605 shares to Chesapeake in connection with the Marcellus acquisition. GIP held 1,509,722 general partner units representing a 1.0 percent general partner interest in the Partnership, 50 percent of the Partnership IDRs, 10,497,003 common units and 34,538,061 subordinated units. GIP's common and subordinated units represent an aggregate 29.8 percent limited partner interest in the Partnership. The public held 34,674,974 common units, representing a 23.0 percent limited partner interest in the Partnership. In February 2012, GIP completed a public offering of their remaining 10,497,003 common units.

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 22	$ 17,816
Accounts receivable, including $61,030 and $88,009 from related parties at December 31, 2011 and 2010, respectively	81,297	107,095
Other current assets	6,869	6,576
Total current assets	88,188	131,487
Property, plant and equipment:
Gathering systems	2,954,868	2,544,053
Other fixed assets	53,611	41,125
Less: Accumulated depreciation	(480,555)	(358,269)
Total property, plant and equipment, net	2,527,924	2,226,909
Investment in unconsolidated affiliates	886,558
Intangible customer relationships, net	158,621	172,481
Deferred loan costs, net	21,947	15,039
Total assets	3,683,238	2,545,916
Current liabilities:
Accounts payable	57,546	39,619
Accrued liabilities, including $62,823 and $42,674 to related parties at December 31, 2011 and 2010, respectively	85,548	58,372
Total current liabilities	143,094	97,991
Long-term liabilities:
Long-term debt	1,062,900	249,100
Other liabilities	4,099	4,257
Total long-term liabilities	1,066,999	253,357
Commitments and contingencies (Note 13)
Partners' capital:
General partner interest	42,400	35,645
Total partners' capital	2,473,145	2,194,568
Total liabilities and partners' capital	3,683,238	2,545,916
Common Units [Member]
Partners' capital:
Limited partner units	1,561,504	1,285,619
Subordinated Units [Member]
Partners' capital:
Limited partner units	$ 869,241	$ 873,304

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Consolidated Statements Of Cash Flows (Parenthetical)	12 Months Ended
	Dec. 31, 2011
Condensed Consolidated Statements Of Cash Flows [Abstract]
Units issued for acquisition of Appalachia Midstream	9,791,605

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Subsequent Events

12 Months Ended

Dec. 31, 2011

Subsequent Events [Abstract]

Subsequent Events

15. Subsequent Events

On January 11, 2012, the Partnership and CHKM Finance Corp. completed a private placement of $750.0 million in aggregate principal amount of 6.125 percent senior notes due 2022. The Partnership used a portion of the net proceeds to repay all borrowings outstanding under its revolving credit facility and used the balance for general partnership purposes.

On January 27, 2012, the board of directors of the Partnership's general partner declared a cash distribution to the Partnership's unitholders of $0.3900 per unit, or $58.9 million in aggregate. The cash distribution was paid on February 14, 2012 to unitholders of record at the close of business on February 7, 2012.

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Consolidated Statements Of Changes In Partners' Capital (USD $) In Thousands	Predecessor [Member] Members' Equity [Member]	Predecessor [Member]	Successor [Member] Members' Equity [Member]	Successor [Member] Limited Partners Common [Member]	Successor [Member] Limited Partners Subordinated [Member]	Successor [Member] General Partner [Member]	Successor [Member]	Total
Balance at Dec. 31, 2008	$ 1,793,269	$ 1,793,269
Contributions from Chesapeake	659,291	659,291
Net income	(17,374)	(17,374)
Sale of noncontrolling interest in midstream joint venture	587,500	587,500
Noncontrolling interest offering cost	(16,130)	(16,130)
Distribution to noncontrolling interest owner	(10,153)	(10,153)
Balance at Sep. 30, 2009	2,996,403	2,996,403
Net income			50,692				50,692	50,692
Members' equity upon formation			1,741,186				1,741,186
Contribution from predecessor			1,749				1,749
Balance at Dec. 31, 2009			1,793,627				1,793,627
Net income			85,831				85,831
Balance at Aug. 02, 2010
Balance at Dec. 31, 2009			1,793,627				1,793,627
Net income								195,227
Contribution from predecessor								177
Distributions to predecessor, net			(6,574)				(6,574)
Distributions to members			(169,500)				(169,500)
Contribution of net assets to Chesapeake Midstream Partners, L.P.			(1,703,384)	834,658	834,658	34,068
Issuance of common units to public, net of offering and other costs				474,579			474,579
Distribution of proceeds to partner from exercise of over-allotment option				(62,419)			(62,419)
Distribution to unitholders				(14,956)	(14,955)	(611)	(30,522)
Non-cash equity based compensation				150			150
Balance at Dec. 31, 2010				1,285,619	873,304	35,645	2,194,568	2,194,568
Balance at Aug. 02, 2010
Net income				53,607	53,601	2,188	109,396
Balance at Dec. 31, 2010				1,285,619	873,304	35,645	2,194,568	2,194,568
Net income				94,896	94,371	5,070	194,337	194,337
Distribution to unitholders				(98,446)	(98,434)	(4,017)	(200,897)	200,897
Initial public offering costs				(1,280)			(1,280)
Non-cash equity based compensation				1,458			1,458
Issuance of common units				279,257			279,257
Issuance of general partner interests						5,702	5,702
Balance at Dec. 31, 2011				$ 1,561,504	$ 869,241	$ 42,400	$ 2,473,145	$ 2,473,145

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Accounts receivable, from related parties	$ 61,030	$ 88,009
Accrued liabilities, from related parties	$ 62,823	$ 42,674
Common Units [Member]
Units issued	78,876,643	69,083,265
Units outstanding	78,876,643	69,083,265
Subordinated Units [Member]
Units issued	69,076,122	69,076,122
Units outstanding	69,076,122	69,076,122

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Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2011

Unconsolidated Affiliates [Abstract]

Unconsolidated Affiliates

10. Unconsolidated Affiliates

Marcellus.   On December 29, 2011, the Partnership acquired from CMD, a wholly owned subsidiary of Chesapeake, and certain of its affiliates, all of the issued and outstanding common units of Appalachia Midstream for approximately $879.3 million. Through the acquisition of Appalachia Midstream, the Partnership will operate 100 percent of and own an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 231 miles of gas gathering pipeline in the Marcellus Shale in Pennsylvania and West Virginia. These 10 gathering systems consist of the Liberty, Victory, Rome and Selbyville gas gathering systems and six other smaller gas gathering systems. The remaining 53 percent interest in these assets is owned primarily by Statoil, Anadarko, Epsilon and Mitsui. Appalachia Midstream operates the assets under 15-year fixed fee gathering agreements.

Unconsolidated Affiliates Financial Information.  The following table sets forth summarized financial information of 100 percent of the 10 gas gathering systems in which the Partnership acquired an interest in December 2011, as follows:

	December 31, 2011
Balance Sheet	($ in thousands)
Current assets	$	38,709
Property, plant, and equipment		745,061
Other assets		213
Total assets	$	783,983
Current liabilities	$	13,137
Other liabilities		90,067
Partner's capital		680,779
Total liabilities and partner's capital	$	783,983

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Document And Entity Information (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Feb. 22, 2012	Jun. 30, 2011
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Entity Registrant Name	CHESAPEAKE MIDSTREAM PARTNERS LP
Entity Central Index Key	0001483096
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		78,899,650
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 698.5

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

11. Asset Retirement Obligations

The following table provides a summary of changes in asset retirement obligations, which are included in other liabilities in the accompanying consolidated balance sheets. Revisions in estimates for the periods presented relate primarily to revisions of current cost estimates, inflation rates and/or discount rates.

	Years Ended December 31,
	2011		2010			2009
	(in thousands)
Asset retirement obligations, beginning of period	$	2,878	$	2,850		$	2,714
Additions		131		229			—
Revisions		193		—			—
Accretion expense		207		211			136
Deletions		—		(412	)		—
Asset retirement obligations, end of period	$	3,409	$	2,878		$	2,850

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Consolidated Statements Of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended	12 Months Ended				9 Months Ended
	Dec. 31, 2009	Dec. 31, 2011		Dec. 31, 2010		Sep. 30, 2009 Predecessor [Member]
Revenues, including revenue from affiliates (Notes 5 and 7)	$ 107,377	$ 565,929		$ 459,153		$ 358,921
Operating expenses
Operating expenses, including expenses from affiliates (Note 5)	31,874	176,851		133,293		146,604
Depreciation and amortization expense	20,699	136,169		88,601		65,477
General and administrative expense, including expenses from affiliates (Note 5)	2,854	40,380		31,992		22,782
Impairment of property, plant and equipment and other assets						90,207
Loss on sale of assets	34	739		285		44,566
Total operating expenses	55,461	354,139		254,171		369,636
Operating income (loss)	51,916	211,790		204,982		(10,715)
Other income (expense)
Income from unconsolidated affiliates		433
Interest expense (Note 12)	(619)	(14,884)		(7,426)		(347)
Other income	34	287		102		29
Income (loss) before income tax expense	51,331	197,626		197,658		(11,033)
Income tax expense	639	3,289		2,431		6,341
Net income (loss)	50,692	194,337		195,227		(17,374)
Limited partner interest in net income
Net income		194,337	[1]	109,396	[1]
Less general partner interest in net income		(5,070)		(2,188)
Limited partner interest in net income		$ 189,267		$ 107,208
Net income per limited partner unit - basic and diluted
Common units		$ 1.37		$ 0.78
Subordinated units		$ 1.37		$ 0.78

[1] (1) Reflective of general and limited partner interest in net income since closing the Partnership's IPO on August 3, 2010. See Note 4 to the consolidated financial statements.

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Transactions With Affiliates

12 Months Ended

Dec. 31, 2011

Transactions With Affiliates [Abstract]

Transactions With Affiliates

5. Transactions with Affiliates

Affiliate transactions.  In the normal course of business, natural gas gathering and treating services are provided to Chesapeake and its affiliates. Revenues are derived almost exclusively from Chesapeake, which includes volumes attributable to third-party interest owners that participate in Chesapeake's operated wells.

Contribution of Partnership Assets to the Partnership.  Upon closing of the IPO in August 2010, Chesapeake and GIP conveyed to the Partnership a 100 percent membership interest in Chesapeake MLP Operating, L.L.C., which owned all of the Partnership's assets since September 2009. See Note 1—Description of Business and Basis of Presentation.

Omnibus Agreement.  The Partnership has entered into an omnibus agreement with Chesapeake Midstream Ventures and Chesapeake Midstream Holdings that addresses the following matters:

• Chesapeake's obligation to provide the Partnership with certain rights relating to certain future midstream business opportunities; and

• the Partnership's right to indemnification for certain liabilities and its obligation to indemnify Chesapeake Midstream Ventures and affiliated parties for certain liabilities.

General and Administrative Services and Reimbursement.  Pursuant to a services agreement, Chesapeake and its affiliates provide certain services including legal, accounting, treasury, human resources, information technology and administration. The employees supporting these operations are employees of CEMI or Chesapeake. The consolidated financial statements for the Partnership and the predecessor include costs allocated from Chesapeake and CEMI for centralized general and administrative services, as well as depreciation of assets utilized by Chesapeake's centralized general and administrative functions. Effective October 1, 2009, the Partnership was charged a general and administrative fee from Chesapeake based on the terms of the joint venture agreement. The established terms indicate corporate overhead costs are charged to the Partnership based on actual cost of the services provided, subject to a fee per Mcf cap based on volumes of natural gas gathered. The fee is calculated as the lesser of $0.03065/Mcf gathered or actual corporate overhead costs. General and administrative charges were $23.7 million, $17.0 million and $2.2 million for the years ended December 31, 2011 and 2010, and three months ended December 31, 2009, for the Partnership. General and administrative charges were $14.6 million for the nine months ended September 30, 2009 for the predecessor.

Additional Services and Reimbursement.  At the Partnership's request, Chesapeake also provides the Partnership with certain additional services under the services agreement, including engineering, construction, procurement, business analysis, commercial, cartographic and other similar services to the extent they are not already provided by the seconded employees. In return for such additional services, the general partner reimburses Chesapeake on a monthly basis an amount equal to the time and materials actually spent in performing the additional services. The reimbursement for additional services is not subject to the general and administrative services reimbursement cap.

Chesapeake has agreed to perform all services under the relevant provisions of the services agreement using at least the same level of care, quality, timeliness and skill as it does for itself and its affiliates and with no less than the same degree of care, quality, timeliness and skill as its past practice in performing the services for itself and the Partnership's business during the one year period prior to September 30, 2009. In any event, Chesapeake has agreed to perform such services using no less than a reasonable level of care in accordance with industry standards.

In connection with the services arrangement, the Partnership reimburses GIP for certain costs incurred by GIP in connection with assisting the Partnership in the operation of its business. For the years ended December 31, 2011 and 2010, the cost was $0.6 million and $0.9 million, respectively, for these support services.

The term of the services agreement will extend for additional twelve-month periods unless any party provides 180 days' prior written notice otherwise prior to the expiration of the applicable twelve-month period ending on December 31.

Employee Secondment Agreement.  Chesapeake, certain of its affiliates and the Partnership's general partner have entered into an amended and restated employee secondment agreement pursuant to which specified employees of Chesapeake are seconded to the general partner to provide operating, routine maintenance and other services with respect to the Partnership's business under the direction, supervision and control of the general partner. Additionally, all of the Partnership's executive officers other than its chief executive officer, Mr. Stice, are seconded to the general partner pursuant to this agreement. The general partner, subject to specified exceptions and limitations, reimburses Chesapeake on a monthly basis for substantially all costs and expenses Chesapeake incurs relating to such seconded employees, including the cost of their salaries, bonuses and employee benefits, including 401(k), restricted stock grants and health insurance and certain severance benefits. Charges to the Partnership for the services rendered by such seconded employees were $42.1 million and $30.3 million for the years ended December 31, 2011 and 2010, respectively. These charges include $37.7 million and $28.3 million in operating expenses and $4.4 million and $2.0 million in general and administrative expenses for the years end December 31, 2011 and 2010, respectively, in the accompanying consolidated statements of operations.

The initial term of the employee secondment agreement extends through September 30, 2014. The term will automatically extend for additional twelve month periods unless any party provides 90 days' prior written notice otherwise prior to the expiration of the initial term or the applicable twelve month period. The Partnership's general partner may terminate the agreement at any time upon 90 days' prior written notice.

Shared Services Agreement.  In return for the services of Mr. Stice as the chief executive officer of the Partnership's general partner, its general partner has entered into a shared services agreement with Chesapeake pursuant to which its general partner reimburses certain of the costs and expenses incurred by Chesapeake in connection with Mr. Stice's employment. The general partner is generally expected, subject to certain exceptions, to reimburse Chesapeake for 50 percent of the costs and expenses of the amounts provided to Mr. Stice in his employment agreement; however, the ultimate reimbursement obligation is determined based on the amount of time Mr. Stice actually spends working for the Partnership. The reimbursement obligations of its general partner will continue for so long as Mr. Stice is employed by both the general partner and Chesapeake.

Gas Compressor Master Rental and Servicing Agreement.  The Partnership has entered into a gas compressor master rental and servicing agreement with MidCon Compression, L.L.C., ("MidCon Compression") a wholly owned indirect subsidiary of Chesapeake, pursuant to which MidCon Compression agreed to lease to the Partnership certain compression equipment that the Partnership uses to compress gas gathered on its gathering systems outside the Marcellus Shale and provide certain related services. In return for the lease of such equipment, the Partnership pays specified monthly rates per specified compression units, subject to an annual escalator to be applied on October 1st of each year and a redetermination of such specified monthly rates to market rates effective no later than October 1, 2016. Under the compression agreement, the Partnership granted MidCon Compression the exclusive right to lease and rent compression equipment to the Partnership in the acreage dedications through September 30, 2016. Thereafter, the Partnership will have the right to continue leasing such equipment through September 30, 2019 at market rental rates to be agreed upon between the parties or to lease compression equipment from unaffiliated third parties. MidCon Compression guarantees to the Partnership that the leased compressors will meet specified run time and throughput performance guarantees. The monthly rental rates are reduced for any leased equipment that does not meet these guarantees. The Partnership leases substantially all of the compression capacity for its existing gathering systems in the Marcellus Shale from MidCon Compression under a long-term contract expiring on January 31, 2021 pursuant to which the Partnership has agreed to pay specified monthly rates under a fixed-fee structure subject to an annual escalator. This agreement is not subject to an exclusivity provision. Compressor rental charges from affiliates were $57.6 million, $47.8 million and $11.7 million for the years ended December 31, 2011 and 2010 and three months ended December 31, 2009, respectively. Compressor rental charges from affiliates were $47.3 million for the nine months ended September 30, 2009, for the predecessor. These charges are included in operating expenses in the accompanying consolidated statements of operations.

The Partnership is obligated to maintain general liability and property insurance, including machinery breakdown insurance with respect to the leased equipment. In addition, MidCon Compression has agreed to provide the Partnership with emission testing and other related services at monthly rates. The Partnership or MidCon Compression may terminate these services upon not less than six months notice.

The compression agreement expires on September 30, 2019 but will continue from year to year thereafter, unless terminated by the Partnership no less than 60 days prior to the end of the term or any year thereafter. Additionally, either party may terminate in specified circumstances, including upon the other party's failure to perform material obligations under the compression agreement if such failure is not cured within 60 days after notice thereof.

In connection with the acquisition of the Springridge gathering system, the previously existing above-described gas compressor master rental and servicing agreement was amended and restated, on terms substantially similar to those under the Partnership's original compression agreement, to include the AMI associated with the Springridge natural gas gathering system and to allow for the addition of future AMIs.

Inventory Purchase Agreement.  Upon completion of the IPO, the Partnership entered into an inventory purchase agreement pursuant to which the Partnership agreed beginning as of September 30, 2009 to purchase from Chesapeake, in each case on terms and conditions to be mutually agreed upon by Chesapeake and the Partnership, its first $60.0 million of requirements of pipes that are useful in the conduct of the natural gas gathering, compression, dehydrating, treating and transportation business at a specified price per ton. For the years ended December 31, 2011 and 2010, the Partnership purchased approximately $23.4 million and $36.6 million, respectively, of inventory pursuant to this inventory purchase agreement and incorporated in the Partnership's property, plant and equipment, thus satisfying the terms of this agreement.

Gas Gathering Agreements.  The Partnership is party to (i) a 20-year gas gathering agreement with respect to the Barnett Shale and the Mid-Continent region with certain subsidiaries of Chesapeake that was entered into in connection with the creation of its predecessor in September 2009, (ii) a 20-year gas gathering agreement with respect to the Barnett Shale with Total that was entered into in connection with an upstream joint venture transaction between Chesapeake and Total E&P in January 2010, (iii) a 10-year gas gathering agreement with certain subsidiaries of Chesapeake that was entered into concurrent with the closing of the Partnership's acquisition of the Springridge gas gathering system in the Haynesville Shale in December 2010 and (iv) through Appalachia Midstream, 15-year gas gathering agreements with certain subsidiaries of Chesapeake, Statoil, Anadarko, Epsilon, Mitsui and Chief that the Partnership acquired in connection with the acquisition of Appalachia Midstream in December 2011.

Future revenues under the Partnership's gas gathering agreements will be derived pursuant to terms that will differ between the Partnership's operating regions.

If one of the counterparties to the gas gathering agreements sells, transfers or otherwise disposes to a third party properties within the Partnership's acreage dedications, it will be required to cause the third party to either enter into the existing gas gathering agreement or enter into a new gas gathering agreement with the Partnership on substantially similar terms to the existing gas gathering agreement with the applicable party.

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Net Income Per Limited Partner Unit

12 Months Ended

Dec. 31, 2011

Net Income Per Limited Partner Unit [Abstract]

Net Income Per Limited Partner Unit

4. Net Income per Limited Partner Unit

The Partnership's net income attributable to the Partnership Assets for periods including and subsequent to the Partnership's acquisitions of the Partnership Assets is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to unvested units granted under the LTIP and incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to available cash (as defined by the partnership agreement) for the period. The Partnership's net income allocable to the limited partners is allocated between the common and subordinated unitholders by applying the provisions of the partnership agreement that govern actual cash distributions as if all earnings for the period had been distributed. Accordingly, if current net income allocable to the limited partners is less than the minimum quarterly distribution, or if cumulative net income allocable to the limited partners since August 3, 2010 is less than the cumulative minimum quarterly distributions, more income is allocated to the common unitholders than the subordinated unitholders for that quarterly period.

Basic and diluted net income per limited partner unit is calculated by dividing the limited partners' interest in net income by the weighted average number of limited partner units outstanding during the period. The common units issued during the period are included on a weighted-average basis for the days in which they were outstanding.

The following table illustrates the Partnership's calculation of net income per unit for common and subordinated limited partner units (in thousands, except per-unit information):

	Years Ended
	December 31, 2011		December 31, 2010
Net income.	$	194,337	$	195,227
Less Successor interest in net income (1)		—		85,831
Less general partner interest in net income		5,070		2,188
Limited partner interest in net income	$	189,267	$	107,208
Net income allocable to common units	$	94,896	$	53,607
Net income allocable to subordinated units		94,371		53,601
Limited partner interest in net income	$	189,267	$	107,208
Net income per limited partner unit – basic and diluted
Common units	$	1.37	$	0.78
Subordinated units		1.37		0.78
Total limited partner units	$	1.37	$	0.78
Weighted average limited partner units outstanding – basic and diluted
Common units		69,371,194		69,083,265
Subordinated units		69,076,122		69,076,122
Total		138,447,316		138,159,387

⁽¹⁾  Includes net income attributable to the initial assets up to August 3, 2010.

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Quarterly Financial Data

12 Months Ended

Dec. 31, 2011

Quarterly Financial Data [Abstract]

Quarterly Financial Data

16. Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data for 2011 and 2010 are as follows ($ in thousands except per share data):

	Quarters Ended
	March 31, 2011		June 30, 2011		September 30, 2011		December 31, 2011
Total revenues	$	123,529	$	133,217	$	140,105	$	169,078
Gross profit(a)		80,968		88,933		96,872		122,305
Net income		38,776		41,083		48,173		66,305
Net income attributable to Chesapeake Midstream Partners, L.P.(b)		38,776		41,083		48,173		66,305
Net income per limited partner unit(b)	$	0.27	$	0.29	$	0.34	$	0.46
	Quarters Ended
	March 31, 2010		June 30, 2010		September 30, 2010		December 31, 2010
Total revenues	$	95,386	$	101,239	$	100,060	$	162,468
Gross profit(a)		64,693		68,854		65,966		126,347
Net income		34,914		37,017		33,414		89,882
Net income attributable to Chesapeake Midstream Partners, L.P.(b)		n/a		n/a		19,514		89,882
Net income per limited partner unit(b)	$	n/a	$	n/a	$	0.14	$	0.64

^(a)  Total revenue less operating costs.

^(b)  Reflective of general and limited partner interest in net income since closing the Partnership's IPO on August 3, 2010. See Note 4 to the consolidated financial statements.

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Long-Term Debt And Interest Expense

12 Months Ended

Dec. 31, 2011

Long-Term Debt And Interest Expense [Abstract]

Long-Term Debt And Interest Expense

12. Long-Term Debt and Interest Expense

The following table presents the Partnership's outstanding debt as of December 31, 2011 and December 31, 2010 (in thousands):

	December 31, 2011		December 31, 2010
Revolving credit facility	$	712,900	$	249,100
5.875% Senior Notes due April 2021		350,000		—
Total long-term debt	$	1,062,900	$	249,100

Revolving Bank Credit Facility.   On September 30, 2009, the newly created joint venture closed a new $500 million secured revolving bank credit facility to fund capital expenditures associated with the joint venture's building of additional natural gas gathering systems and for general corporate purposes. At the same time, the predecessor amended and restated its existing revolving bank credit facility to reduce its capacity from $460 million to $250 million, among other changes. The outstanding balance under the predecessor's credit facility was repaid at the time of the amendment. In conjunction with the establishment of the new facilities, the predecessor expensed $4 million of previously capitalized debt issuance costs associated with this amendment and capitalized $5.7 million associated with the amended $250 million credit facility. The Partnership capitalized $11.5 million of debt issuance costs associated with the $500 million credit facility.

On August 2, 2010, the Partnership amended the $500 million joint venture credit facility. The amended revolving bank credit facility was to mature in July 2015, and provide up to $750.0 million of borrowing capacity, including a sub-limit of $25.0 million for same-day swing line advances and a sub-limit of $50.0 million for letters of credit. In addition, the credit facility contained an accordion feature that allowed the Partnership to increase the available borrowing capacity under the facility up to $1.0 billion, subject to the satisfaction of certain closing conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the credit facility.

On June 10, 2011, the Partnership amended its senior secured revolving credit facility and extended its maturity to June 2016. As amended, the credit facility provides up to $800 million of borrowing capacity and includes a sub-limit of $50 million for same-day swing line advances and a sub-limit of $50 million for letters of credit. In addition, the credit facility contains an accordion feature that allows the Partnership to increase the available borrowing capacity under the facility up to $1 billion, subject to the satisfaction of certain closing conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the credit facility.

On December 20, 2011 the Partnership amended its revolving credit facility to increase total borrowing capacity. The revolving credit facility, as amended to date, provides the Partnership up to $1 billion of borrowing capacity and includes a sub-limit up to $50 million for same-day swing line advances and a sub-limit up to $50 million for letters of credit. In addition, the revolving credit facility contains an accordion feature that allows the Partnership to increase the available borrowing capacity under the facility up to $1.25 billion, subject to the satisfaction of certain conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the facility. The revolving credit facility matures in June 2016. As of December 31, 2011 the Partnership had approximately $712.9 million of borrowings outstanding under its revolving credit facility.

Borrowings under the revolving credit facility are available to fund working capital, finance capital expenditures and acquisitions, provide for the issuance of letters of credit and for general partnership purposes. The revolving credit facility is secured by all of the Partnership's assets, and loans thereunder (other than swing line loans) bear interest at the Partnership's option at either (i) the greater of (a) the reference rate of Wells Fargo Bank, NA, (b) the federal funds effective rate plus 0.50 percent or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (LIBOR), plus 1.00 percent, each of which is subject to a margin that varies from 0.625 percent to 1.50 percent per annum, according to the Partnership's leverage ratio (as defined in the agreement), or (ii) the Eurodollar rate plus a margin that varies from 1.625 percent to 2.50 percent per annum, according to the Partnership's leverage ratio. If the Partnership reaches investment grade status, the Partnership will have the option to release the security under the credit facility and amounts borrowed will bear interest under a specified ratings-based pricing grid. The unused portion of the credit facility is subject to commitment fees of (a) 0.25 percent to 0.40 percent per annum while the Partnership is subject to the leverage-based pricing grid, according to the Partnership's leverage ratio and (b) 0.20 percent to 0.35 percent per annum while the Partnership is subject to the ratings-based pricing grid, according to its senior unsecured long-term debt ratings.

Additionally, the revolving credit facility contains various covenants and restrictive provisions which limit the Partnership and its subsidiaries' ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of the Partnership's assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness. If the Partnership fails to perform its obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. The revolving credit facility also has cross default provisions that apply to any other indebtedness the Partnership may have with an outstanding principal amount in excess of $15 million.

The revolving credit facility agreement contains certain negative covenants that (i) limit the Partnership's ability, as well as the ability of certain of its subsidiaries, among other things, to enter into hedging arrangements and create liens and (ii) require the Partnership to maintain a consolidated leverage ratio, and an EBITDA to interest expense ratio, in each case as described in the credit facility agreement. The revolving credit facility agreement also provides for the discontinuance of the requirement for the Partnership to maintain the EBITDA to interest expense ratio if the Partnership reaches investment grade status. The revolving credit facility agreement also requires the Partnership to maintain a consolidated leverage ratio of 5.0 to 1.0 (or 5.5 to 1.0 during an approximate two-quarter period following the completion of certain acquisitions). The Partnership was in compliance with all covenants under the agreement at December 31, 2011.

Senior Notes.   On April 19, 2011, the Partnership and CHKM Finance Corp., a wholly owned subsidiary of Chesapeake MLP Operating, L.L.C., completed a private placement of $350.0 million in aggregate principal amount of 5.875 percent senior notes due 2021 (the "2021 Notes"). The Partnership used a portion of the net proceeds to repay borrowings outstanding under its revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $7.8 million are being amortized over the life of the 2021 Notes.

The 2021 Notes will mature on April 15, 2021 and interest is payable on the 2021 Notes on April 15 and October 15 of each year, beginning on October 15, 2011. The Partnership has the option to redeem all or a portion of the 2021 Notes at any time on or after April 15, 2015, at the redemption price specified in the indenture, plus accrued and unpaid interest. The Partnership may also redeem the 2021 Notes, in whole or in part, at a "make-whole" redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to April 15, 2015. In addition, the Partnership may redeem up to 35 percent of the 2021 Notes prior to April 15, 2014 under certain circumstances with the net cash proceeds from certain equity offerings. The Indenture contains covenants that, among other things, limit the Partnership's ability and the ability of certain of its subsidiaries to: (1) sell assets including equity interests in its subsidiaries; (2) pay distributions on, redeem or purchase its units, or redeem or purchase its subordinated debt; (3) make investments; (4) incur or guarantee additional indebtedness or issue preferred units; (5) create or incur certain liens; (6) enter into agreements that restrict distributions or other payments from certain subsidiaries to the Partnership; (7) consolidate, merge or transfer all or substantially all of its assets; (8) engage in transactions with affiliates; and (9) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the 2021 Notes achieve an investment grade rating from either of Moody's Investors Service, Inc. or Standard & Poor's Ratings Services and no default, as defined in the Indenture, has occurred or is continuing, many of these covenants will terminate.

On January 11, 2012, the Partnership and CHKM Finance Corp. completed a private placement of $750.0 million in aggregate principal amount of 6.125 percent senior notes due 2022. See Note 15 for discussion regarding the transaction.

The Partnership, as the parent company, has no independent assets or operations. The Partnership's operations are conducted by its subsidiaries through its operating company subsidiary, Chesapeake MLP Operating, L.L.C. Each of Chesapeake MLP Operating, L.L.C. and the Partnership's other subsidiaries is a guarantor, other than CHKM Finance Corp., an indirect wholly owned subsidiary of the Partnership whose sole purpose is to act as co-issuer of any debt securities. Each guarantor is a wholly owned subsidiary of the Partnership. The guarantees registered under the registration statement are full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the Indenture. There are no significant restrictions on the ability of the Partnership or any guarantor to obtain funds from its subsidiaries by dividend or loan. None of the assets of the Partnership or a guarantor represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.

Fair Value.   Estimated fair values are determined by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. Based on the borrowing rates available at December 31, 2011 for debt with similar terms and maturities, the carrying value of long-term debt approximates its fair value.

Capitalized Interest.   Interest expense was net of capitalized interest of $9.5 million, $2.6 million, $0.3 million, and $6.5 million for the years ended December 31, 2011 and 2010, three months ended December 31, 2009, and nine months ended September 30, 2009, respectively, for the Partnership and the predecessor.

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Property, Plant And Equipment

12 Months Ended

Dec. 31, 2011

Property, Plant And Equipment [Abstract]

Property, Plant And Equipment

8. Property, Plant and Equipment

A summary of the historical cost of the Partnership's property, plant and equipment is as follows:

	Estimated Useful Lives (Years)		December 31, 2011			December 31, 2010
	($ in thousands)
Gathering systems		20	$	2,954,868		$	2,544,053
Other fixed assets		2 through 39		53,611			41,125
Total property, plant and equipment				3,008,479			2,585,178
Accumulated depreciation				(480,555	)		(358,269	)
Total net, property, plant and equipment			$	2,527,924		$	2,226,909

Included in gathering systems is $122.6 million and $329.5 million at December 31, 2011 and 2010, respectively, that is not subject to depreciation as the systems were under construction and had not been put into service.

Depreciation expense was $124.7 million, $88.4 million and $19.2 million for the years ended December 31, 2011 and 2010, and three months ended December 31, 2009, respectively, for the Partnership. Depreciation expense was $64.4 million for the nine months ended September 30, 2009, respectively, for the predecessor.

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Income Taxes

6. Income Taxes

As discussed in Note 2, as a master limited partnership, the Partnership is a pass-through entity and not subject to federal income taxes and most state income taxes with the exception of Texas Franchise Tax. For federal and state income tax purposes other than Texas, all income, expenses, gains, losses and tax credits generate flow through to the owners, and accordingly, do not result in a provision for income taxes. Income tax (benefit) expense for the nine months ended September 30, 2009, is as follows:

	Predecessor
	Nine Months Ended September 30, 2009
	(in thousands)
Current	$	—
Deferred		6,341
Total income tax (benefit) expense presented in the Statements of Operations	$	6,341

Reconciliation of income tax expense at the U.S. Federal Statutory Income Tax Rate to actual tax expense (Statutory Rate Reconciliation) for the nine months ended September 30, 2009, is as follows:

	Predecessor
	Nine Months Ended September 30, 2009
	($ in thousands)
Income tax expense, computed at the statutory rate of 35%	$	(3,862	)
Effect of state income tax, net of federal income tax effect		423
Effect of non-taxable entities		9,780
Total income tax expense (benefit)	$	6,341
Effective tax rate		(57.47	)%

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Concentration Of Credit Risk

12 Months Ended

Dec. 31, 2011

Concentration Of Credit Risk [Abstract]

Concentration Of Credit Risk

7. Concentration of Credit Risk

Chesapeake and Total are the only customers from whom revenues exceeded 10 percent of consolidated revenues for the years ended December 31, 2011, 2010, and 2009, for the Partnership and its predecessor. The percentage of revenues from Chesapeake, Total and other customers are as follows:

	Years Ended December 31,
	2011			2010			2009
Chesapeake		82.9	%		82.2	%		98.0	%
Total		14.0			14.8			—
Other		3.1			3.0			2.0
Total		100	%		100	%		100	%

Financial instruments that potentially subject the Partnership and its predecessor to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. On December 31, 2011 and 2010, respectively, cash and cash equivalents were invested in a non-interest bearing account and money market funds with investment grade ratings.

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Business Combinations

12 Months Ended

Dec. 31, 2011

Business Combinations [Abstract]

Business Combinations

9. Business Combinations

Marcellus.    On December 29, 2011, the Partnership acquired from CMD all of the issued and outstanding common units of Appalachia Midstream for total consideration, which is subject to a customary post-closing working capital adjustment, of $879.3 million, consisting of 9,791,605 common units and $600.0 million in cash that was financed with a draw on the Partnership's revolving credit facility. The base purchase price of $879.3 million was increased by $7.3 million due to initial working capital adjustments through December 31, 2012. Through the acquisition of Appalachia Midstream, the Partnership operates 100 percent of and owns an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 231 miles of gas gathering pipeline in the Marcellus Shale. The remaining 53 percent interest in these assets is owned primarily by Statoil, Anadarko, Epsilon and Mitsui. Gross throughput for these assets at December 31, 2011, was just over 1.0 Bcf per day (approximately 470 Mmcf per day net to the Partnership). Appalachia Midstream operates the assets under 15-year fixed fee gathering agreements.

The results of operations presented and discussed in this annual report include results of operations from the Appalachia Midstream for the two-day period from closing of the acquisition on December 29, 2011, through December 31, 2011. The Partnership's interest in the gas gathering systems is accounted for as an equity investment and is included in income from unconsolidated affiliate. For this period, income from unconsolidated affiliate attributable to Marcellus operations was $0.4 million. The purchase price in excess of the value underlying the gas gathering system assets and working capital is approximately $461.2 million and is attributable to customer relationships acquired. This intangible asset will be amortized over a 15 year period on a straight-line basis.

Springridge.    On December 21, 2010, the Partnership completed the Springridge acquisition for $500.0 million in cash that was funded with a draw on the Partnership's revolving credit facility of approximately $234.0 million plus approximately $266.0 million of cash on hand. The Springridge gathering system is primarily located in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, the Partnership entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication, annual fee redetermination and a minimum volume commitment.

The results of operations presented and discussed in this annual report include results of operations from the Springridge gathering system for the 10-day period from closing of the acquisition on December 21, 2010, through December 31, 2010 and all of 2011. For the 10-day period in 2010, revenues and net loss attributable to Springridge operations were $2.1 million and $1.0 million, respectively. The total purchase price of the Springridge acquisition was allocated as follows: gas gathering system assets of $327.5 million and a customer relationship with a value of $172.5 million. The useful life of the customer relationship acquired is estimated to be 15 years and is amortized on a straight-line basis.

The following unaudited pro forma condensed consolidated financial statements for the years ended December 31, 2011 and 2010 are based upon the historical consolidated financial statements of the Partnership and the historical results of operations of the Springridge assets and Appalachia Midstream. The unaudited pro forma condensed consolidated financial statements have been prepared as if Appalachia Midstream acquisition occurred on January 1, 2010, in the case of the unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2011, and as if the Springridge and Appalachia Midstream acquisitions occurred on January 1, 2010, in the case of the unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2010. The pro forma adjustments reflected in the pro forma condensed consolidated financial statements are based upon currently available information and certain assumptions and estimates; therefore, the actual effects of these transactions will differ from the pro forma adjustments. However, the Partnership's management considers the applied estimates and assumptions to provide a reasonable basis for the presentation of the significant effects of certain transactions that are expected to have a continuing impact on the Partnership. In addition, the Partnership's management considers the pro forma adjustments to be factually supportable and to appropriately represent the expected impact of items that are directly attributable to the transfer of the Springridge assets and Appalachia Midstream to the Partnership.

The Partnership expects significant throughput volume growth in 2012 as compared to the historical proforma information presented. CMD has committed to pay us quarterly any shortfall between the actual EBITDA from these assets and specified quarterly targets, with the quarterly targets adding to a total of $100 million in 2012 and $150 million in 2013.

	Year Ended December 31, 2011
	Partnership Historical			Appalachia Midstream		Pro Forma Adjustments			Partnership Pro Forma as Adjusted
	(in thousands)
Revenues, including revenue from affiliates	$	565,929		$	—	$	—		$	565,929
Total Operating Expenses		354,139			—		—			354,139
Income from unconsolidated affiliate		433			41,432		(44,974	)  (a)(b)		(3,109	)
Interest expense		(14,884	)		—		(17,543	)  (c)		(32,427	)
Other income		287			—		—			287
Income tax expense		(3,289	)		—		—			(3,289	)
Net income (loss)	$	194,337		$	41,432	$	(62,517	)	$	173,252
Limited partner interest in net income
Net income									$	173,252
Less general partner interest in net income										(3,465	)
Limited partner interest in net income									$	169,787
Net income per common unit – basic and diluted									$	1.15
Net income per subordinated unit – basic and diluted									$	1.15

	Year Ended December 31, 2010
	Partnership Historical			Appalachia Midstream		Appalachia Midstream Pro Forma Adjustments			Springridge Assets			Springridge Pro Forma Adjustments			Partnership Pro Forma as Adjusted
	(in thousands)
Revenues, including revenue from affiliates	$	459,153		$	—	$	—		$	53,592		$	—		$	512,745
Total Operating Expenses		259,047			—		—			35,151			12,899	(a)(d)		307,097
Income from unconsolidated affiliates		—			19,978		(44,974	) (a)(b)		—			—			(24,996	)
Interest expense		(2,550	)		—		(23,940	) (c)		(107	)		(6,937	) (e)		(33,534	)
Other income		102			—		—			—			—			102
Income tax expense		(2,431	)		—		—			—			—			(2,431	)
Net income (loss)	$	195,227		$	19,978	$	(68,914	)	$	18,334		$	(19,836	)	$	144,789
Limited partner interest in net income
Net income															$	144,789
Less general partner interest in net income																(2,896	)
Limited partner interest in net income															$	141,893
Net income per common unit – basic and diluted															$	0.96
Net income per subordinated unit – basic and diluted															$	0.96

(a) The amortization of the customer relationship associated with the Springridge and Appalachia Midstream acquisition. The intangible asset is amortized on a straight-line basis over 15 years.

(b) Adjustment to record depreciation expense for the gathering systems acquired in the Appalachia Midstream acquisition to reflect the expense that would have been recorded by the Partnership.

(c) Interest at 2.94 percent and 3.99 percent for the years ended December 31, 2011 and 2010, respectively, on the debt incurred to fund the Appalachia Midstream acquisition. The debt is variable, and a 125 basis point increase in the interest rate would have increased interest expense $7.5 million for both of the years ended December 31, 2011 and 2010, respectively.

(d) The incurrence of incremental general and administrative expense per contractual agreement with Chesapeake. The established terms indicate corporate overhead costs will be charged to the Partnership based on a fee per Mcf of natural gas gathered. The Mcf fee is calculated as the lesser of $0.03/Mcf gathered or actual corporate overhead costs.

(e) Interest at 3.01 percent on the debt incurred to fund the Springridge acquisition. The debt is variable and a 125 basis point increase in the interest rate would have increased interest expense $2.9 million for the twelve months ended December 31, 2010.

Amortization of the intangible asset during each of the next five years is expected to be $11.5 million for Springridge. Amortization expense for Springridge was $11.3 million for the year ended December 31, 2011, with no amortization expense in 2010.

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Recently Issued Accounting Standards

12 Months Ended

Dec. 31, 2011

Recently Issued Accounting Standards [Abstract]

Recently Issued Accounting Standards

14. Recently Issued Accounting Standards

The Financial Accounting Standards Board ("FASB") recently issued the following standard which the Partnership reviewed to determine the potential impact on its financial statements upon adoption.

In December 2010, the FASB issued guidance on disclosure of supplementary pro forma information for business combinations. The guidance specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The guidance also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, non-recurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenues and earnings. These amendments are effective prospectively for business combinations with an acquisition date on or after December 15, 2010.

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Consolidated Statements Of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended	12 Months Ended		9 Months Ended
	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Sep. 30, 2009 Predecessor [Member]
Cash flows from operating activities:
Net income	$ 50,692	$ 194,337	$ 195,227	$ (17,374)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	20,699	136,169	88,601	65,477
Deferred income taxes				6,341
Impairment of property, plant and equipment and other assets				90,207
Income from unconsolidated affiliates		(433)
Loss on sale of assets	34	739	285	44,566
Other non-cash items	(39)	5,747	4,976	(282)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	(70,792)	31,501	58,172	(29,553)
Increase (decrease) in other assets	(136)	(292)	(4,833)	(1,901)
Increase (decrease) in accounts payable	(23,630)	11,258	7,474	(82,112)
Increase (decrease) in accrued liabilities	37,902	19,990	(32,811)	25,379
Net cash provided by operating activities	14,730	399,016	317,091	100,748
Cash flows from investing activities:
Additions to property, plant and equipment	(46,377)	(418,834)	(216,303)	(756,883)
Acquisition of gathering system assets			(500,000)
Investment in unconsolidated affiliates		(600,000)
Proceeds from sale of assets	25	1,730	4,823	65,889
Net cash used in investing activities	(46,352)	(1,017,104)	(711,480)	(690,994)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	100,744	1,576,700	529,300	870,373
Payments on long-term debt borrowings	(68,817)	(1,112,900)	(324,300)	(1,318,200)
Proceeds from issuance of common units, net of offering costs			474,579
Proceeds from issuance of senior notes		350,000	(30,522)
Distributions to unit holders		(200,897)
Distributions to partners			(231,919)	(10,153)
Contribution from predecessor			177
Contributions from Chesapeake				567,828
Proceeds from sale of noncontrolling interest				587,500
Joint venture transaction costs				(16,130)
Debt issuance cost	(337)	(11,332)	(5,113)	(16,950)
Initial public offering costs		(1,280)
Other adjustments		3
Net cash provided by financing activities	31,590	600,294	412,202	664,268
Net increase (decrease) in cash and cash equivalents	(32)	(17,794)	17,813	74,022
Cash and cash equivalents, beginning of period	35	17,816	3	82,025
Cash and cash equivalents, end of period	3	22	17,816	156,047
Supplemental disclosure of non-cash investing activities:
Changes in accounts payable and other liabilities related to purchases of property, plant and equipment	(2,812)	8,589	12,633	(52,521)
Changes in other liabilities related to asset retirement obligations	136	324	28	(2,893)
Contributions of property, plant and equipment to Chesapeake	1,749		11,705	91,462
Supplemental disclosure of non-cash financing activities:
Issuance of 9,791,605 units to Chesapeake for acquisition of Appalachia Midstream		279,257
Issuance of general partner interests		5,702
Supplemental disclosure of cash payments for interest	877	16,957	3,607	7,478
Supplemental disclosure of cash payments for taxes		$ 2,830	$ 645

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Partnership Distributions

12 Months Ended

Dec. 31, 2011

Partnership Distributions [Abstract]

Partnership Distributions

3. Partnership Distributions

The partnership agreement requires that, within 45 days subsequent to the end of each quarter, beginning with the quarter ended September 30, 2010, the Partnership distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. During the years ended December 31, 2011 and 2010, the Partnership paid cash distributions to its unitholders of approximately $200.9 million and $30.5 million, respectively, representing the four distributions in 2011 and only one distribution in 2010. See also Note 15—Subsequent Events concerning distributions approved in January 2012 for the quarter ended December 31, 2011.

Available cash.   The amount of available cash (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter less the amount of cash reserves established by the Partnership's general partner to provide for the proper conduct of its business, including reserves to fund future capital expenditures, to comply with applicable laws, or its debt instruments and other agreements, or to provide funds for distributions to its unitholders and to its general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement.

Minimum Quarterly Distribution.   The partnership agreement provides that, during the subordination period, the common units are entitled to distributions of available cash each quarter in an amount equal to the minimum quarterly distribution, which is $0.3375 per common unit for a full fiscal quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Furthermore, arrearages do not apply to and therefore will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the subordination period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to or greater than the minimum quarterly distribution.

The subordination period will lapse at such time when the Partnership has earned and paid at least the quarterly minimum distribution per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2013. Also, if the Partnership has earned and paid at least 150 percent of the minimum quarterly distribution on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of removal. When the subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages. All subordinated units are held indirectly by Chesapeake and GIP.

General Partner Interest and Incentive Distribution Rights.   The Partnership's general partner is entitled to two percent of all quarterly distributions that the Partnership makes prior to its liquidation. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. The general partner's initial two percent interest in the Partnership's distributions may be reduced if the Partnership issues additional limited partner units in the future (other than the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and its general partner does not contribute a proportionate amount of capital to the Partnership to maintain its two percent general partner interest. After distributing amounts equal to the minimum quarterly distribution to common and subordinated unitholders and distributing amounts to eliminate any arrearages to common unitholders, the Partnership's general partner is entitled to incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds specified target levels shown below:

	Total quarterly distribution per unit		Unitholders			General partner
Minimum Quarterly Distribution		$0.3375		98.0	%		2.0	%
First Target Distribution		up to $0.388125		98.0	%		2.0	%
Second Target Distribution		above $0.388125 up to $0.421875		85.0	%		15.0	%
Third Target Distribution		above $0.421875 up to $0.50625		75.0	%		25.0	%
Thereafter		above $0.50625		50.0	%		50.0	%

The table above assumes that the Partnership's general partner maintains its 2 percent general partner interest, that there are no arrearages on common units and the general partner continues to own the IDRs. The maximum distribution sharing percentage of 50.0 percent includes distributions paid to the general partner on its two percent general partner interest and does not include any distributions that the general partner may receive on limited partner units that it owns or may acquire.

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2011

Commitments And Contingencies [Abstract]

Commitments And Contingencies

13. Commitments and Contingencies

Environmental obligations.   The Partnership is subject to various environmental-remediation and reclamation obligations arising from federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. Management believes there are currently no such matters that will have a material effect on the Partnership's results of operations, cash flows or financial position and has not recorded any liability in these financial statements.

Litigation and legal proceedings.   From time to time, the Partnership is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceedings for which a final disposition could have a material effect on the Partnership's results of operations, cash flows or financial position. There was not an accrual for legal contingencies as of December 31, 2011 or 2010.

Lease commitments.  Certain property, equipment and operating facilities are leased under various operating leases. Costs are also incurred associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations.

Rental expense related to leases was $60.7 million, $50.1 million, $11.7 million, and $48.2 million for the years ended December 31, 2011 and 2010, three months ended December 31, 2009, nine months ended September 30, 2009, respectively, for the Partnership and the predecessor. The Partnership's remaining contractual lease obligations as of December 31, 2011 represent obligations with an affiliate of Chesapeake for compression equipment as compression services are needed to support pipeline that is being placed in service in future periods.

Future minimum rental payments due under operating leases as of December 31, 2011 are as follows:

	(in thousands)
2012	$	36,549
2013		23,053
2014		14,848
2015		4,049
2016		997
Thereafter		—
Future minimum lease payments(1)	$	79,496

⁽¹⁾  Includes the Partnership's minimum rental payments for Appalachia Midstream acquired on December 29, 2011.