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

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

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

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

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. [ ]

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 [X] Accelerated Filer [ ] 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, 2013 was approximately $5,133,723,566.

Unless the context otherwise requires, references in this report to the “Partnership,” “we,” “our,” “us” or like terms refer to Access Midstream Partners, L.P. (NYSE: ACMP) and its subsidiaries. The “GIP I Entities” refers to, collectively, GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P. and GIP-C Holding (CHK), L.P., the “GIP II Entities” refers to certain entities affiliated with Global Infrastructure Investors II, LLC, and “GIP” refers to the GIP I Entities and their affiliates and the GIP II Entities, collectively. “Williams” refers to The Williams Companies, Inc. (NYSE: WMB).

We are a growth-oriented publicly traded Delaware limited partnership formed in 2010 to own, operate, develop and acquire natural gas, natural gas liquids (“NGLs”) and oil gathering systems and other midstream energy assets. We are principally focused on natural gas and NGL gathering, the first segment of midstream energy infrastructure that connects natural gas and NGLs 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 our midstream services to Chesapeake Energy Corporation (“Chesapeake”); Total E&P USA, Inc. and Total Gas & Power North America, Inc., wholly owned subsidiaries of Total S.A. (“Total”); Mitsui & Co. (“Mitsui”); Anadarko Petroleum Corporation (“Anadarko”); Statoil ASA (“Statoil”) and other leading producers under long-term, fixed-fee contracts. We operate assets in the Barnett Shale region in north-central Texas; the Eagle Ford Shale region in South Texas; the Haynesville Shale region in northwest Louisiana; the Marcellus Shale region primarily in Pennsylvania and West Virginia; the Niobrara Shale region in eastern Wyoming; the Utica Shale region in eastern Ohio; and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian Basins.

Our gathering systems collect natural gas and NGLs from unconventional plays. We generate our revenues and fees through long-term, fixed-fee gas gathering, treating, compression and processing contracts, all of which limit our direct commodity price exposure. Our contracts provide us with extensive acreage dedications in our operating regions. These agreements generally contain the following terms:

Our principal executive offices are located at 525 Central Park Drive, Oklahoma City, Oklahoma 73105, and our telephone number is (877) 413-1023. Our website is located at www.accessmidstream.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.

Our Corporate Governance Guidelines, Code of Business Conduct and Ethics and the charters of the audit committee, compensation committee, conflicts committee and risk committee of our general partner’s board of directors are also available on our website. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s corporate secretary at our principal executive offices.

The following table summarizes our average daily throughput for the year ended December 31, 2013 and assets as of December 31, 2013:

General. Our gathering systems in the 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 consist of 28 interconnected gathering systems and 859 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, natural 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 the Barnett Shale gathering systems for the year ended December 31, 2013, was 1.045 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 95 compressor units providing a combined 150,945 horsepower of compression.

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

General. Our gathering systems in the Eagle Ford Shale region are primarily located in Dimmit, La Salle, Frio, Zavala, McMullen and Webb counties in Texas and consist of 11 gathering systems and 870 miles of pipeline. Natural gas in the Eagle Ford formation is typically wet and requires processing to remove NGLs prior to delivery into the pipeline grid. Natural gas produced in the Eagle Ford formation typically needs to be treated to remove small to large amounts of carbon dioxide and hydrogen sulfide.

Average throughput for these assets for the year ended December 31, 2013, was 0.263 Bcf per day. We connect our gathering systems to central receipt points into which production from multiple wells is gathered. Chesapeake’s pad drilling concept is used extensively around the Eagle Ford gathering systems. Our Eagle Ford gathering systems have pipeline diameters ranging from four-inch well connection lines to a 16-inch major trunk line and contains 68 compressor units providing a combined 93,847 horsepower of compression.

Delivery points. Our Eagle Ford gathering systems’ primary delivery points are the following:

Haynesville Shale natural gas production is characterized as “lean” and typically needs to be treated to remove small amounts of carbon dioxide and hydrogen sulfide. The core areas of the Haynesville Shale are characterized by thicker natural gas bearing geological zones, which results in higher initial production rates.

General. Our Springridge 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 consists of 274 miles of pipeline.

A portion of our assets in the Springridge gathering system have been designed and developed to accommodate the urban setting in and around the city of Shreveport, Louisiana. Average throughput on our Springridge gathering system for the year ended December 31, 2013, was 0.302 Bcf per day. 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 10 compressor units providing a combined 20,195 horsepower of compression.

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

General. Our Mansfield gathering system in the Haynesville Shale region is primarily located in DeSoto and Sabine Parishes, Louisiana, in one of the core areas of the Haynesville Shale and, as of December 31, 2013, consists of 308 miles of pipeline.

Average throughput on our Mansfield gathering system for the year ended December 31, 2013, was 0.367 Bcf per day. Our Mansfield gathering system has pipeline diameters ranging from six-inch well connection lines to a 24-inch major trunk line and we connect our gathering system to central receipt points into which production from multiple wells is gathered and treated.

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

General. Through our wholly owned subsidiary Appalachia Midstream Services, L.L.C. (“Appalachia Midstream”), we operate 100 percent of and own an approximate average 47 percent interest in 10 natural gas gathering systems that consist of approximately 823 miles of gathering pipeline in the Marcellus Shale region. The majority of our volumes in the region are gathered from 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 natural gas production can be characterized as “lean” dry gas or “rich” wet gas depending on its location. In general, the natural gas in the northern Marcellus Shale is lean and typically requires little to no treatment to remove contaminants. Southern Marcellus Shale natural gas is wet and typically requires treatment and processing to remove NGLs prior to delivery into the pipeline grid. Average gross throughput for the Marcellus Shale assets for the year ended December 31, 2013 was just over 2.212 Bcf per day (approximately 1.019 Bcf 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 systems’ primary delivery points are the following:

General. We own a 50 percent operating interest in a joint venture that owns two natural gas gathering systems and has committed to build processing facilities in the Niobrara Shale region. Our gathering systems in the Niobrara Shale region are primarily located in Converse County, Wyoming and consist of two interconnected separate gathering systems and 132 miles of pipeline. This area is characterized by thicker natural gas bearing geological zones, which results in higher initial production rates. Typically, the natural gas produced in this basin is characterized as wet and requires treatment and processing to remove NGLs prior to delivery to the pipeline grid.

Average throughput in the Niobrara Shale region for the year ended December 31, 2013, was 0.015 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. Our Niobrara gathering systems have pipeline diameters ranging from four-inch well connection lines to 16-inch major trunk lines and are connected to 13 compressor units providing a combined 15,665 horsepower of compression.

Delivery Points. Our Niobrara gathering systems are connected to the following downstream transportation pipelines:

General. We own a 66 percent operating interest in a joint venture that owns a wet gas gathering system, a 100 percent ownership interest in four lean gas gathering systems and a 49 percent non-operating interest in a joint venture that owns two processing trains and is currently constructing two additional processing trains, a fractionation facility, NGL storage capacity and other ancillary assets. Typically, natural gas produced in the western and central portions of the Utica Shale is wet and requires processing to remove NGLs prior to delivery into the pipeline grid. Natural gas produced in the eastern portions of the Utica Shale is generally lean and requires little to no treatment to remove contaminants.

Our gathering systems in the Utica Shale region are primarily located in northeast Ohio and consist of 265 miles of pipeline. The systems connect to five compression facilities that provide a combined compression capacity of 63,505 horsepower. Average throughput in the Utica Shale gathering region for the year ended December 31, 2013, was 0.107 Bcf per day.

Delivery Points. Our Utica gathering systems are connected to the following downstream transportation pipelines:

Our Mid-Continent gathering systems extend across portions of Oklahoma, Texas, Arkansas and Kansas. Included in the 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.

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 1,635 miles of pipeline. Our Anadarko Basin and Northwest Oklahoma region gathering systems had an average throughput for the year ended December 31, 2013 of 0.431 Bcf per day. These systems are connected to 74 compressor units providing a combined 77,220 horsepower of compression.

Within the Anadarko Basin and Northwest Oklahoma, we are primarily focused on servicing Chesapeake’s production from the Colony Granite Wash, Texas Panhandle Granite Wash and Mississippi Lime plays. Natural gas production from these areas of the Anadarko Basin and Northwest Oklahoma typically contains a significant amount of NGLs and requires processing prior to delivery to end-markets. In addition, Enbridge Energy Partners L.P. (“Enbridge”) operates 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 gathering 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 Pipeline Partners L.P. (“Atlas Pipeline Partners”), as well as local market pipelines such as those owned by Enable Midstream Partners, LP (“Enable”). These pipelines provide access to Midwest and northeastern U.S. markets as well as intrastate markets.

General. The Permian Basin assets are located in west Texas and consist of approximately 486 miles of pipeline across the Permian and Delaware basins. Average throughput on our Permian Basin gathering systems for the year ended December 31, 2013, was 0.082 Bcf per day. The gathering systems have pipeline diameters ranging from four inches to 16 inches and are connected to 18 compressor units providing a combined 15,780 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 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.

Our other Mid-Continent region assets consist of gathering 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 and our assets include approximately 684 miles of pipeline. These gathering systems are generally localized and gather specific production for re-delivery into established pipeline markets. Average throughput on these gathering systems for the year ended December 31, 2013, was 0.068 Bcf per day. The gathering systems have pipeline diameters ranging from four inches to 24 inches and are connected to 32 compressor units providing a combined 15,735 horsepower of compression.

We continue to see a trend by our producer customers of shifting drilling activity from dry gas shale plays, such as those in the Barnett Shale and Haynesville Shale regions, to NGL-rich plays, such as the Eagle Ford region, Marcellus region, Niobrara region, Utica region and Mid-Continent region. We believe this trend is likely to continue for the foreseeable future. Our contractual protections of minimum volume commitments and rate redetermination work to support our financial performance in the Barnett Shale and Haynesville Shale relative to decreases in production.

The expansion of our services into the Eagle Ford, Niobrara and Utica Shale regions expanded our opportunity to serve producer customers in liquids-rich areas, including entering the business line of processing natural gas and fractionation to produce NGLs. We expect that continued construction activity in 2014 will generate significant increased gathering, processing and fractionation capacity.

The natural gas price environment has generally resulted in lower drilling activity in our dry gas shale plays, resulting in fewer new well connections in certain of the areas in which we operate. We have no control over this activity. In addition, commodity price movements will affect production rates and the level of capital invested by our producer customers 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.

Given that substantially all of the natural gas gathered and transported through our gathering systems and processing facilities is owned by producer customers with whom we have long-term gathering contracts, we do not currently face significant competition for our natural gas volumes. In addition, Chesapeake and Total have dedicated all of the natural gas produced from their 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 Shale region, Eagle Ford Shale region, Niobrara Shale region and certain areas in the Utica Shale region. Chesapeake and other producers have provided long-term acreage dedications in the Marcellus Shale region, Mid-Continent region and certain of our Utica Shale regions.

We face competition for production drilled outside of our acreage dedications 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:

At every level of our operations, our employees are critical to our success and committed to operational excellence. Our senior management team has extensive experience building, acquiring and managing midstream and other assets. Their focus is on optimizing our business and expanding operations. At 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, 2013, our general partner employed approximately 1,411 people who operate our business. None of these employees are covered by collective bargaining agreements and our general partner considers its employee relations to be good.

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, as amended, (“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 natural gas and hazardous liquids pipeline facilities, while the PSIA and its reauthorizations establish mandatory integrity inspections for all U.S. oil and natural gas transmission pipelines (and, going forward, possibly gathering lines) in defined “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 high-consequence areas, authorizes DOT to study whether or not to promulgate regulations requiring the use of automatic and remote-controlled shut-off valves for new or replaced pipelines. 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 pipelines to consider seismicity in their assessments of pipeline integrity. PHMSA adopted new rules pursuant to the PSRC increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations.

We or the entities in which we own an interest inspect our key pipelines regularly using internal inspection equipment rented from third-party suppliers. These 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 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 jurisdictional 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 natural 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.

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. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our systems due to these regulations.

The Energy Policy Act of 2005 amended the NGA and NGPA to prohibit fraud and manipulation in natural gas markets. FERC subsequently issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud. FERC’s anti-manipulation rules apply to intrastate sales and gathering activities that have a “nexus” to FERC-jurisdictional transactions. FERC is authorized to impose civil penalties of up to $1.0 million per day per violation and grant other relief, such as ordering refunds, or revoking operating authority.

Under the Commodity Exchange Act, the CFTC is directed to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act, the CFTC has adopted anti-market manipulation regulations that prohibit, among other things, fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to assess fines of up to the greater of $1,000,000 and triple the monetary gain for violations of its anti-market manipulation regulations.

Our operation of pipelines, plants and other facilities for the gathering, treating, compression and processing 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:

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.

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 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 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.

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 adopted 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 August 16, 2012, the EPA published revisions to existing the existing oil and gas New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAP”) as well as created a new NSPS (Subpart OOOO) for oil and gas production, transmission and distribution facilities. NSPS Subpart OOOO established new standards for equipment leaks, natural gas processing plants, storage vessels, gas sweetening units, compressors and pneumatic devices. These new rules also include additional requirements for our upstream customers who operate hydraulically-fractured natural gas wells particularly commencing in 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response to some of these challenges, on April 12, 2013, the EPA published a proposed amendment extending compliance dates for certain storage vessels. The final amendment was finalized on August 2, 2013, and published in the Federal Register on September 23, 2013. This rule could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

Effective in August 2011, the EPA also issued a final rule modifying existing regulations under the Clean Air Act that establish NSPS for manufacturers, owners and operators or new, modified and reconstructed stationary internal combustion engines. These rules, to which EPA issued minor amendments on January 14, 2013, may also require us to incur significant additional expenditures, including the purchase and installation of new emissions control equipment. We are continuing to evaluate the potential impacts of these new regulations on our operations. 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 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.

The Federal Water Pollution Control Act (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 or local 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 flows.

Hydraulic fracturing is an important and common practice that is used by our customers to stimulate production of hydrocarbons 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. On May 24, 2013, the federal Bureau of Land Management published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian lands that replaces a prior draft rule issued by the agency in May 2012. The revised proposed rule would continue to require public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface, which could impact our customers’ operations. 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.”

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. We diligently track the status of threatened and endangered species as well as the many candidate species to ensure we are prepared for any changes that have the potential to affect our operations. Tracking is accomplished by directly monitoring the U.S. Fish and Wildlife Service’s actions and communications as well as through close involvement with industry trade associations and their environmental committees.

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. 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. Beginning in September of 2012 with 2011 data, certain midstream facilities are now required to submit annual reports of greenhouse gas emissions to the EPA. 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.

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.

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.”

We are currently 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, 2013, Chesapeake accounted for approximately 74 percent of the natural gas volumes on our gathering systems and 84 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:

If our producers do not increase the volumes of natural gas they provide to our gathering systems and processing facilities, our growth strategy and ability to increase cash distributions to our unitholders may be adversely affected.

Our ability to increase the throughput on our gathering systems and at our processing facilities will be substantially dependent on receiving increased volumes from producers. Other than the scheduled increases in the minimum volume commitments provided for in our gas gathering agreements with certain producers in certain geographic areas, 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 NGL-rich areas and, in response to historically low natural gas prices, announced that it was reducing dry gas drilling, completions, production and leasehold expenditures wherever feasible, including by operating fewer drilling rigs in the Barnett Shale and Haynesville Shale regions. A reduction in the natural gas volumes supplied by Chesapeake, Total or other producers could result in reduced throughput on our gathering systems and adversely impact our ability to grow our operations and increase cash distributions to our unitholders.

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 outstanding common units and two percent general partner interest. The amount of cash we can distribute principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

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 amount of cash available for distribution will also be reduced by the amount 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.

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 may reduce the volumes Chesapeake delivers to our gathering systems and processing facilities. Furthermore, a higher level of indebtedness at Chesapeake increases the risk that it may default on its obligations, including under its gas gathering and processing agreements with us. 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 and processing facilities.

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 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.

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

In addition to Chesapeake, we rely on Total and other producers such as Statoil, Anadarko and Mitsui for a significant amount of the natural gas that we gather, treat, compress and process. 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 and processing agreements with us. Not all of our counterparties under our gas gathering and processing 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.

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 and NGLs, which is dependent on factors beyond our control. Any decrease in the volumes of natural gas and NGLs that we gather or process could adversely affect our business and operating results.

The volumes that support our business are dependent on the level of production from natural gas and NGL wells connected to our gathering systems and processing facilities, 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 and processing facilities, we must obtain new sources of natural gas and NGLs. The primary factors affecting our ability to obtain non-dedicated sources of natural gas and NGLs 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 and processing facilities or the rate at which production from a well declines. In addition, we have no control over 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, NGLs 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 oil and natural gas reserves. In general terms, the prices of natural gas, NGLs, 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 potential for export of 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 the prices of natural gas, NGLs or oil 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, treating and processing assets. Because of these factors, even if new natural gas and oil 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 and processing facilities 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 gathering systems and processing facilities 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.

If one of our gas gathering or processing 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 and processing 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 gathering systems. Additionally, if a gas gathering agreement is terminated as to only a particular Barnett Shale gathering system, the minimum volume commitments may be reduced for natural gas volumes that would have been gathered on the terminated gathering system. After the termination of a gas gathering or processing agreement, a customer might not continue to contract with us to provide gathering or processing 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 or processing 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 and processing 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 and processing agreements contain provisions relating to, among other items, periodic fee redeterminations, the cost of service mechanism, changes in laws affecting our operations and fuel and lost and unaccounted for gas. These and other provisions of our gas gathering and processing agreements might not operate as intended.

The fee redetermination, cost of service mechanism and other provisions of our gas gathering and processing 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 and cost of service provisions do not take into consideration all expenses and other variables, including certain operating expenditures, that affect our return on invested capital. In addition, our gathering rates may be adjusted upward or downward following a fee redetermination or cost of service calculation, subject to specified caps in certain cases. The change in law provisions contained in our gas gathering and processing 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 would subject us to direct commodity price risk.

If these or other provisions of our gas gathering and processing 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.

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

We do not obtain independent evaluations of natural gas and NGL reserves connected to our systems and processing facilities. 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 and Haynesville Shale regions and fee redetermination and cost of service provisions, if the total reserves or estimated life of the reserves connected to our gathering systems or processing facilities are less than we anticipate and we are unable to secure additional sources of natural gas and NGLs, 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 commercial agreements and the applicable governing provisions of our joint venture arrangements in the Utica Shale and certain of our Mid-Continent regions. 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.

We are generally required to make capital expenditures under our commercial agreements in order to provide midstream services to our producer customers. 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 (i) in our Barnett Shale and Haynesville Shale regions during the respective minimum volume commitment periods, (ii) in our Eagle Ford Shale, Marcellus Shale, Niobrara Shale and Utica Shale regions, generally subject to our option to connect discussed below, and (iii) with respect to our Mid-Continent region prior to June 30, 2019, to use commercially reasonable efforts to do the same. In the Eagle Ford Shale, Marcellus Shale, Niobrara Shale and Utica Shale regions, 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. Under the applicable governing provisions of our joint venture arrangements in the Utica Shale and certain of our Mid-Continent regions, we are obligated to make capital contributions to fund the development of necessary gathering and processing infrastructure facilities in the applicable region. 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 (during the minimum volume commitment period), certain producers in the Barnett Shale and Haynesville Shale acreage dedication, as their 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. In addition, if we are delayed in making a connection to an operated drilling pad or well, certain producers in the Eagle Ford Shale, Marcellus Shale, Niobrara Shale, Utica Shale and Haynesville Shale acreage dedication are entitled to a daily penalty payment that escalates in amount every 15 days. If we are delayed in making a connection to an operated drilling pad or well for a period of time in the Eagle Ford Shale, Marcellus Shale, Niobrara Shale, Utica Shale and Haynesville Shale regions, the proposed drilling pad and well will be released from the acreage dedication under the applicable gas gathering agreement. As a result of its release, the producers or their affiliates may construct a separate gas gathering system to connect to the drilling pad or well. 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.

If we fail to make a required capital contribution under the applicable governing provisions of our joint venture arrangements, we could be deemed to be in default under the joint venture agreement. Under our joint venture arrangements in the Utica Shale and certain of our Mid-Continent regions, our joint venture partners could be permitted to fund any deficiency resulting from our failure to make such capital contribution, which would result in a dilution of our ownership interest, or could have the option to purchase all of our existing interest in the joint venture, which could have an adverse effect on our results of operations and ability to make or increase cash distributions to our unitholders.

To the extent that our cash from operations is insufficient to fund our expansion capital expenditures or required joint venture capital contributions, we may be required to incur borrowings or raise capital through public or private debt or equity offerings in order to fund such expansion capital expenditures or required capital contributions. 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 expenditures deducted from operating surplus is 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 (through Appalachia Midstream), Niobrara Shale region, Utica Shale region and certain of the Mid-Continent 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:

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, Niobrara, Utica and certain of our Mid-Continent 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 and NGL production dedicated to us pursuant to our gas gathering and processing agreements with 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 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 new producers over time. However, we have historically provided gathering and related services to producers other than Chesapeake and its joint interest partners on only a limited basis, and we may not be able to attract any material volumes from new customers to our systems. Our efforts to attract new customers may be adversely affected by our need to prioritize allocating capital expenditures towards connecting new operated drilling pads and new operated wells for certain 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 new customers.

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

Our gas gathering systems and processing facilities 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, transport or process 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 and ability to make cash distributions to our unitholders could be adversely affected.

If we are unable to make acquisitions on economically acceptable terms from third parties, our future growth could be reduced, and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.

Our ability to grow may depend, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. If we are unable to make such accretive acquisitions from 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 may be reduced. Furthermore, any acquisition involves potential risks, including, among other things:

We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have material adverse effects on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

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, treat, compress and process rather than the value of the underlying commodity. 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, natural gas and NGL prices could have a material adverse effect on our business, results of operations,

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 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:

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, we operate in metropolitan areas and that 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 underground pipeline systems. 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 receive 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 receive substantially all of the compression capacity for our existing gathering systems from MidCon Compression, L.L.C. (“MidCon Compression”), a wholly owned subsidiary of Chesapeake, under long-term contracts pursuant to which we have agreed to pay specified monthly rates under a fixed-fee structure subject to an annual escalation provision. In some of our operating areas we have granted MidCon Compression the exclusive right to provide compression equipment to us through periods ending, depending on the particular region, from 2016 to 2018. Thereafter, we have the right to continue receiving such equipment in these areas at market rates to be agreed upon by the parties or to receive compression equipment from third parties. If market rates for compression are less than the specified monthly rates under our compression agreements, then the rates we pay for compression under the agreements to MidCon Compression 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.

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:

Furthermore, our revolving credit facility contains covenants requiring us to maintain a consolidated leverage ratio of not more than 5.50 to 1.0 (or 5.0 to 1.0 after we have released all collateral upon achieving investment grade status) and an interest coverage ratio of not less than 2.5 to 1.0.

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 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 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 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 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, compression and processing 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 oil and 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. On August 16, 2012, the EPA published final regulations under the federal Clean Air Act, as amended (the “CAA”) that established new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. On September 23, 2013, the EPA published an amendment extending compliance dates for certain storage vessels. This rule could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. On May 24, 2013, the federal Bureau of Land Management published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian lands that replaces a prior draft rule issued by the agency in May 2012. The revised proposed rule would continue to require public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface, which could impact our customers’ operations.

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. Some states and municipalities are also considering adopting other laws and regulations that could restrict hydraulic fracturing operations or ban them altogether. 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 or processing facilities 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, compression and processing 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 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 August 16, 2012, the EPA issued rules that would establish new air emission controls for oil and natural gas processing operations. Specifically, the EPA’s 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. These rules, effective October 15, 2012, may require a number of modifications to our customers’ as well as our operations, including the installation of new equipment, which may 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 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. 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. Certain midstream facilities are now required to submit annual reports of greenhouse gas emissions to the EPA beginning in September 2012 with 2011 data. 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.

If our assets became subject to regulation by FERC or regulations of state and local agencies were to change, or if we fail to comply with market behavior rules, 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. 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, which has been subject to extensive litigation and interpretation. The classification and regulation of our gathering and intrastate transportation facilities are subject to future determinations by FERC, the courts or Congress. If an individual facility and/or services provided by it were determined not to be exempt from FERC regulation, the rates for, and terms and conditions of services provided by such facility could be changed, resulting in decreased revenues, increased operating costs, and depending upon the facility in question, the changes 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. The CFTC also enforces rules prohibiting market manipulation. If we fail to comply with anti-market manipulation of rules of FERC or the CFTC, we could be subject to significant fines and penalties.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. 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 PHMSA revises its requirements to include additional pipelines in the integrity management program, the inclusion of our pipelines could have a material adverse effect on our operations and cash flows.

The DOT, through PHMSA, has adopted and enforces safety standards and procedures applicable to our pipelines. PHMSA requires integrity inspections for all U.S. oil and natural gas transmission pipelines in defined “high-consequence areas,” While our pipelines are currently exempt from such integrity management requirements, PHMSA is considering whether to revise the integrity management requirements to include additional pipelines in the integrity management program, which could have a material adverse effect on our operations and cash flows to the extent our pipelines are included in such a program.

Terrorist or cyber-attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on our business, financial condition or results of operations.

Terrorist attacks and threats, cyber-attacks, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist or cyber-attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. We do not maintain specialized insurance for possible liability resulting from a cyber-attack on our assets that may shut down all or part of our business. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

The GIP II Entities and Williams, through their joint ownership of Access Midstream Ventures, L.L.C. (“Access 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 the GIP II Entities, Williams and Access 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.

Access Midstream Ventures, which is owned and controlled by the GIP II Entities and Williams, 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 the GIP II Entities and/or Williams and Access 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, Access Midstream Ventures. Conflicts of interest will arise between the GIP II Entities, Williams, Access 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 the GIP II Entities, Williams and/or Access Midstream Ventures over our interests and the interests of our common unitholders. These conflicts include the following situations, among others:

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 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 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:

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:

In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that 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 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 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 13 members, four of whom are independent. Access Midstream Ventures, which is owned and controlled by the GIP II Entities and Williams, is the sole member of our general partner and has the right to appoint our general partner’s entire board of directors, including our four 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 the consent of the GIP II Entities and Williams.

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 limited partner interests, voting together as a single class, is required to remove our general partner. As of February 19, 2014, the GIP II Entities and Williams together own an aggregate of 54.9 percent of our outstanding limited partner interests.

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.

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 Access 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 indirectly jointly owned and controlled by the GIP II Entities and Williams. 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, Access Midstream Ventures. As of February 19, 2014, the GIP II Entities and Williams each directly own a 50 percent membership interest in, and jointly control, Access Midstream Ventures. Access Midstream Ventures has the right to appoint our general partner’s entire board of directors, including our independent directors. We expect that conflicts may arise in the future between the GIP II Entities, on the one hand, and Williams, 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 the GIP II Entities and Williams, 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:

The GIP II Entities and Williams 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 19, 2014, the GIP II Entities and Williams together hold an aggregate of approximately 98.1 million common units and approximately 12.6 million Class B units. After the record date for the distribution on common units for the fiscal quarter ending December 31, 2014, each Class B unit will become convertible into a common unit on a one-for-one basis at the option of either us or the holder thereof. Additionally, we have agreed to provide the GIP II Entities and Williams with certain registration rights with respect to their units. 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.

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 19, 2014, the GIP II Entities and Williams together own approximately 51.9 percent of our outstanding common units (exclusive of Class B units). At the end of the conversion period for the Class B units, assuming no additional issuances of common units (other than upon the

conversion of the Class B units) or other events that affect any of the GIP II Entities’ and Williams’ ownership, the GIP II Entities and Williams will own an aggregate of approximately 54.9 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:

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.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, 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. 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. 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 at any time. For example, from time to time members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any such changes, or other proposals, will ultimately be enacted; however, 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. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take, and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may 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 that 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 for federal income tax purposes 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. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest 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 for federal income tax purposes 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 effect 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 effect 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 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 if relief was not available, as described below) for one fiscal 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 currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for 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 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, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia and Wyoming. 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.

Substantially all of our pipelines, which are located in Arkansas, Kansas, Louisiana, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming 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 two office buildings located at 525 Central Park Drive, Oklahoma City, Oklahoma, under a lease that expires December 31, 2022, with annual renewal options. 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.”

Our common units are listed on the NYSE under the symbol “ACMP.” 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 on the common units during each quarter over the last two fiscal years.

The last reported sale price of our common units on the NYSE on February 19, 2014 was $56.91. As of February 19, 2014, there were approximately 40 unitholders of record of our 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 12,553,322 Class B units and ownership interests in the general partner, for which there is no established public trading market. All of the Class B units and general partner interests are held by affiliates of our general partner. Class B units are entitled to paid-in-kind distributions.

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions, minimum quarterly distributions, paid-in-kind distributions and incentive distribution rights.

Our partnership agreement requires that, within 45 days after the end of each quarter, 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.

Upon payment of the cash distribution for the second quarter of 2013, the subordination period with respect to our 69,076,122 subordinated units expired and all outstanding subordinated units converted into common units on a one-for-one basis on August 15, 2013. Prior to the conversion date, the subordinated units were not entitled to receive any distributions until the common units received the minimum quarterly distribution of $0.3375 per common unit plus any arrearages from prior quarters. The conversion did not impact the total number of our outstanding units representing limited partner interests.

The Class B units are not entitled to cash distributions. Instead, prior to conversion into common units, the Class B units receive quarterly distributions of additional paid-in-kind Class B units. The amount of each quarterly distribution per Class B unit is the quotient of the quarterly distribution paid to our common units by the volume-weighted average price of the common units for the 30-day period prior to the declaration of the quarterly distribution to common units. Effective on the business day after the record date for the distribution on common units for the fiscal quarter ending December 31, 2014, each Class B unit will become convertible at the election of either us or the holder of such Class B unit into a common unit on a one-for-one basis. In the event of our liquidation, the holder of Class B units will be entitled to receive out of our assets available for distribution to the partners the positive balance in each such holder’s capital account in respect of such Class B units, determined after allocating our net income or net loss among the partners. All Class B units are held indirectly by affiliates of our general partner.

Under our partnership agreement, the Class C units became convertible into common units on a one-for-one basis at the election of either us or the holders of the Class C units on February 10, 2014 (the first business day following the record date for the Partnership’s 2013 fourth quarter cash distribution). After February 10, 2014, we received notice from certain of the GIP II Entities and Williams, as holders of the Class C units, of their election to convert all of the Class C units. All of the outstanding Class C units were converted into common units on a one-for-one basis effective February 19, 2014. The common units resulting from this conversion will participate pro rata with the other common units in quarterly distributions. The conversion did not impact the total number of our outstanding units representing limited partner interests.

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 Class B 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.

Our general partner has adopted the Access 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.

On December 20, 2012, we sold (i) 5,929,025 Class B Units to each of Williams and the GIP II Entities and (ii) 5,599,634 Class C Units to each of Williams and the GIP II Entities, in each case pursuant to that certain Subscription Agreement described and included in our Current Report on Form 8-K filed December 12, 2012. We received aggregate proceeds of approximately $700.0 million in exchange for the sale of the Class B Units and the Class C Units, inclusive of the capital contribution made by the general partner to maintain its two percent interest in us.

In connection with public offerings of our common units in March 2013 and December 2012, the general partner made additional capital contributions to us of $8.4 million and $12.1 million, respectively, to maintain its two percent interest in us. These issuances were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

On August 15, 2013, all of our existing subordinated units were converted into common units on a one-for-one basis. On February 19, 2014, all of our existing Class C units were converted into common units on a one-for-one basis.

In connection with public offerings under the our Equity Distribution Agreement during the fourth quarter of 2013, our general partner made additional capital contributions to us of $1.0 million on February 14, 2014 to maintain its two percent interest in us. These issuances were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

During the fiscal year ended December 31, 2013, 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, that have not been previously disclosed in a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.

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 the GIP I Entities 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, on December 29, 2011 we closed the Marcellus acquisition and on December 20, 2012, we closed the CMO 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, 2013			Year Ended December 31, 2012			Year Ended December 31, 2011			Year Ended December 31, 2010			Three Months Ended December 31, 2009			Nine Months Ended September 30, 2009
		($ in thousands)
Statement of Operations Data:
Revenues⁽¹⁾	$	1,073,222		$	608,447		$	565,929		$	459,153		$	107,377		$	358,921
Operating expenses		338,716			197,639			176,851			133,293			31,874			146,604
Depreciation and amortization expense		296,179			165,517			136,169			88,601			20,699			65,477
General and administrative expense		104,332			67,579			40,380			31,992			2,854			22,782
Impairment of property, plant and equipment and other assets⁽²⁾		—			—			—			—			—			90,207
Other operating (income) expense⁽³⁾		2,092			(766	)		739			285			34			44,566
Total operating expenses		741,319			429,969			354,139			254,171			55,461			369,636
Operating income (loss)		331,903			178,478			211,790			204,982			51,916			(10,715	)
Income from unconsolidated affiliates		130,420			67,542			433			—			—			—
Interest expense		(116,778	)		(64,739	)		(14,884	)		(7,426	)		(619	)		(347	)
Other income		827			320			287			102			34			29
Income (loss) before income taxes		346,372			181,601			197,626			197,658			51,331			(11,033	)
Income tax expense⁽⁴⁾		5,223			3,214			3,289			2,431			639			6,341
Net income (loss)		341,149			178,387			194,337			195,227			50,692			(17,374	)
Net income (loss) attributable to noncontrolling interests		5,124			(68	)		—			—			—			—
Net income (loss) attributable to Access Midstream Partners, L.P.	$	336,025		$	178,455		$	194,337		$	195,227		$	50,692		$	(17,374	)
Net income per common unit – basic and diluted⁽⁵⁾	$	1.01			1.11			1.37			0.78			n/a			n/a
Net income per subordinated unit – basic and diluted⁽⁵⁾		0.93			1.14			1.37			0.78			n/a			n/a
Distribution per unit		2.04			1.71			1.48			0.55			n/a			n/a
Balance Sheet Data (at period end):
Net property, plant and equipment	$	5,290,800		$	4,632,048		$	2,527,924		$	2,226,909		$	1,776,415		$	2,870,547
Total assets		7,917,446			6,561,100			3,683,238			2,545,916			1,958,675			3,232,840
Total debt		3,253,664			2,500,000			1,062,900			249,100			44,100			12,173
Total partners’ capital		4,352,790			3,796,506			2,473,145			2,194,568			1,793,627			2,996,403
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	563,962		$	318,130		$	399,016		$	317,091		$	14,730		$	100,748
Investing activities		(1,556,418	)		(2,685,965	)		(1,017,104	)		(711,480	)		(46,352	)		(690,994	)
Financing activities		944,691			2,432,807			600,294			412,202			31,590			664,268
Key Performance Metrics:
Adjusted EBITDA⁽⁶⁾	$	858,633		$	477,882		$	349,473		$	293,970		$	72,683		$	189,564
Distributable cash flow⁽⁶⁾		635,125			340,073			261,960			218,989			n/a			n/a
Capital expenditures		1,058,599			350,500			418,834			216,303			46,377			756,883
Operational Data:
Throughput, Bcf/d ⁽⁷⁾		3.699			2.845			2.176			1.595			1.550			2.108

Our CMO Acquisition and Williams’ Acquisition of 50 Percent of Our General Partner

On December 20, 2012, we acquired from Chesapeake Midstream Development, L.P. (“CMD”), a wholly owned subsidiary of Chesapeake, and certain of CMD’s affiliates, 100 percent of the issued and outstanding equity interests in Chesapeake Midstream Operating, L.L.C. (“CMO”) for total consideration of $2.16 billion (the “CMO Acquisition”). As a result of the CMO Acquisition, we own certain midstream assets in the Eagle Ford, Utica and Niobrara regions. The CMO Acquisition also extended our existing assets and operations in the Haynesville, Marcellus and Mid-Continent regions. The acquired assets included, in the aggregate, approximately 1,675 miles of pipeline and 4.3 million (gross) dedicated acres as of the date of the acquisition. We also assumed various gas gathering and processing agreements associated with the assets that have terms ranging from 10 to 20 years and that, in certain cases, include cost of service or fee redetermination mechanisms.

The results of operations presented and discussed in this annual report include results of operations from the CMO assets for the full year of operations in 2013 and for the twelve-day period from closing of the CMO Acquisition on December 20, 2012 through December 31, 2012.

Concurrently with the CMO Acquisition, the GIP I Entities sold to Williams 34,538,061 of our subordinated units and 50 percent of the outstanding equity interests in Access Midstream Ventures, L.L.C., the sole member of our general partner (“Access Midstream Ventures”), for cash consideration of approximately $1.82 billion (the “Williams Acquisition”). As a result of the Williams Acquisition, the GIP II Entities and Williams together indirectly own and control our general partner and the GIP I Entities do not have any ownership interest in us or our general partner.

On December 29, 2011, we acquired from CMD all of the issued and outstanding equity interests in Appalachia Midstream Services, L.L.C. (“Appalachia Midstream”) for total consideration of $879.3 million, consisting of 9,791,605 common units and $600.0 million in cash. Through Appalachia Midstream, we currently operate 100 percent of and own an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 549 miles of gas gathering pipeline in the Marcellus Shale. The remaining 53 percent interest in these assets is owned primarily by Statoil, Anadarko and Mitsui. Appalachia Midstream operates the assets under 15-year, 100 percent fixed fee gathering agreements that include significant acreage dedications and cost of service mechanisms. In addition, CMD committed to pay us quarterly for any shortfall between the actual EBITDA generated by these gas gathering systems and specified quarterly targets totaling $100 million in 2012 and $150 million in 2013. EBITDA generated by these gas gathering

systems exceeded the specified EBITDA commitments in 2012 and 2013 and no additional revenue related to the commitments was realized.

The results of operations presented and discussed in this annual report include results of operations from Appalachia Midstream for the full year of operations in 2013 and 2012 and the three-day period from closing of the acquisition on December 29, 2011, through December 31, 2011.

We operate assets in the Barnett Shale region in north-central Texas, the Eagle Ford Shale region in southwest Texas, the Haynesville Shale region in northwest Louisiana, the Marcellus Shale region primarily in Pennsylvania and West Virginia, the Niobrara Shale region in Wyoming, the Utica Shale region in northeast Ohio, and the Mid-Continent region, which includes the Anadarko, Arkoma, Delaware and Permian Basins.

For the year ended December 2013, we generated approximately 33 percent of our fees from our gathering systems in the Barnett Shale region, approximately 21 percent of our fees from our gathering systems in the Eagle Ford Shale region, approximately nine percent of our fees from our gathering systems in the Haynesville Shale region, approximately 19 percent of our fees from our gathering systems in the Marcellus Shale region, approximately one percent of our fees from our gathering systems in the Niobrara Shale region, approximately four percent of our fees from our gathering systems and processing facilities in the Utica Shale region and approximately 13 percent of our fees from our gathering systems and processing facilities in the Mid-Continent region.

The results of our operations are primarily driven by the volumes of natural gas and natural gas liquids (“NGLs”) we gather, treat, compress and process across our gathering systems and processing facilites. We currently provide all of our midstream services pursuant to fixed fee contracts, which limit our direct commodity price exposure, and we generally do not take title to the natural gas or NGLs we gather. We have entered into long-term gas gathering and processing agreements with Chesapeake, Total, Statoil, Anadarko, Mitsui, and other producers. Pursuant to our commercial agreements, our producer customers have agreed to dedicate extensive acreage in our operating regions.

We generate substantially all of our fees through long-term, fixed-fee natural gas gathering, treating, compression and processing contracts, all of which limit our direct commodity price exposure.

Future fees under our commercial agreements with producers will be derived pursuant to terms that will vary depending on the applicable operating region. The following outlines the key economic provisions of our commercial agreements by region.

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

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

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

Marcellus Shale Region. Under our gas gathering agreements with certain subsidiaries of Chesapeake, Statoil, Anadarko, Epsilon Energy Ltd. (“Epsilon”), Mitsui and Chief Oil & Gas LLC (“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:

Niobrara Shale Region. Under our gas gathering and processing agreements with Chesapeake and RKI Exploration & Production, LLC (“RKI”), we have agreed to provide the following services for the fees and obligations outlined below:

Utica Shale Region. Under our commercial agreements with Chesapeake, Total and Enervest, we have agreed to provide the following services for the fees and obligations outlined below:

Mid-Continent Region. Under our gas gathering agreements with our producer customers, we have agreed to provide the following services for the fees and obligations outlined below:

As part of the CMO Acquisition, we acquired a 33.33 percent equity interest in Ranch Westex JV LLC, which we own jointly with Regency Energy Partners, LP and Anadarko Pecos Midstream LLC. Under a gas processing agreement with Chesapeake and Anadarko, Ranch Westex JV LLC provides natural gas processing services under a cost of service fee arrangement.

All Regions. If one of the counterparties these the gas gathering and processing agreements sells, transfers or otherwise disposes of properties within the our acreage dedications to a third party, it does so subject to the terms of the gas gathering and processing agreements, including our dedication, and it will be required to cause the third party to acknowledge and take assignment of the counterparty’s obligations under the existing gas gathering and processing agreements with us, subject to our consent. Our producer customers’ dedication of the natural gas produced from applicable properties under our gas gathering and processing agreements will run with the land in order to bind successors to the producer customers’ interest, as well as any interests in the dedicated properties subsequently acquired by the producer customer.

On June 15, 2012, in connection with the closing of the first portion of the acquisition by the GIP II Entities of Chesapeake’s ownership interest in us (the “GIP Acquisition”), we entered into a letter agreement with Chesapeake regarding the terms on which Chesapeake provides certain transition services to us and our general partner. Among other things, the letter agreement provided for the continuation of our services agreement with Chesapeake until December 31, 2013. On June 29, 2012, we entered into an amendment to the letter agreement amending certain terms relating to the insurance coverage to be provided under our services agreement. On December 20, 2012, in connection with the CMO Acquisition, we entered into an amendment to the letter agreement amending certain terms relating primarily to the extension of transition services for technology related services through March 2014 and through June 2014 for certain field communication support services.

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) segment operating income, (v) Adjusted EBITDA and (vi) distributable cash flow.

Our management analyzes our performance based on the aggregate amount of throughput volumes on our gathering systems in our operating 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 and liquids volumes currently gathered by our competitors and our ability to cost-effectively construct new infrastructure to connect new wells.

Our revenues are driven primarily by our contractual terms with our customers and the actual volumes of natural gas we gather, treat, compress and process. Our revenues 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 as well as fee redetermination and cost of service provisions in our other regions. We contract with producers to gather or process natural gas or liquids from individual wells located near our gathering systems or processing facilities. 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 and liquids that we gather to the extent necessary to meet required specifications of third-party takeaway pipelines. For the years ended December 31, 2013, 2012 and 2011, Chesapeake accounted for approximately 74 percent, 81 percent and 84 percent, respectively, of the natural gas volumes on our gathering systems and 84 percent, 81 percent and 83 percent, respectively, of our revenues. The Partnership’s revenues exclude revenue attributable to the Partnership’s equity investments as those revenues are accounted for as part of the Partnership’s investments in unconsolidated affiliates.

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

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 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.

Prior to the CMO Acquisition, our operations were organized into a single business segment. As a result of the CMO Acquisition, we added assets in three new operating regions. Effective January 1, 2013, our chief operating decision

maker began to measure performance and allocate resources based on geographic segments. Our operations are divided into eight operating segments: Barnett Shale, Eagle Ford Shale, Haynesville Shale, Marcellus Shale, Niobrara Shale, Utica Shale, Mid-Continent and Corporate.

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”).

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:

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 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:

	Year Ended December 31, 2013			Year Ended December 31, 2012			Year Ended December 31, 2011
	($ in thousands)
Reconciliation of Adjusted EBITDA and Distributable cash flow to net cash provided by operating activities:
Net cash provided by operating activities	$	563,962		$	318,130		$	399,016
Changes in assets and liabilities		46,394			(33,472	)		(62,457	)
Distribution of earnings received from unconsolidated affiliates		(82,871	)		—			—
Interest expense		116,778			64,739			14,884
Current income tax expense		5,223			3,214			3,289
Other non-cash items		(28,316	)		(9,048	)		(5,747	)
Acquisition transaction costs		—			17,432			—
EBITDA from unconsolidated affiliates⁽¹⁾		202,453			116,887			488
Expense for non-cash equity awards		35,010			—			—
Implied minimum volume commitment		—			—			—
Adjusted EBITDA	$	858,633		$	477,882		$	349,473
Maintenance capital expenditures		(110,000	)		(75,184	)		(74,000	)
Cash portion of interest expense		(108,285	)		(59,411	)		(10,224	)
Income tax expense		(5,223	)		(3,214	)		(3,289	)
Distributable cash flow	$	635,125		$	340,073		$	261,960

We have provided a detailed comparison for the years ended December 31, 2013, 2012 and 2011 in the chart and discussion below.

	Year Ended December 31, 2013			Year Ended December 31, 2012			Year Ended December 31, 2011
	($ in thousands, except per unit data)
Revenues⁽¹⁾	$	1,073,222		$	608,447		$	565,929
Operating expenses		338,716			197,639			176,851
Depreciation and amortization expense		296,179			165,517			136,169
General and administrative expense		104,332			67,579			40,380
Other operating (income) expense		2,092			(766	)		739
Total operating expenses		741,319			429,969			354,139
Operating income		331,903			178,478			211,790
Income from unconsolidated affiliates		130,420			67,542			433
Interest expense		(116,778	)		(64,739	)		(14,884	)
Other income		827			320			287
Income before income tax expense		346,372			181,601			197,626
Income tax expense		5,223			3,214			3,289
Net income		341,149			178,387			194,337
Net income (loss) attributable to noncontrolling interest		5,124			(68	)		—
Net income attributable to Access Midstream Partners, L.P.	$	336,025		$	178,455		$	194,337
Operating Data:
Throughput, Bcf/d⁽²⁾		3.699			2.845			2.176

We present information in this Management’s Discussion and Analysis of Financial Condition and Results of Operations by segment. The segment information appearing in Note 13 of the accompanying Notes to the Condensed Consolidated Financial Statements is presented on a basis consistent with how our chief operating decision maker measures performance and allocates resources. Beginning on January 1, 2013, we conduct our operations in the following segments: Barnett Shale, Eagle Ford Shale, Haynesville Shale, Marcellus Shale, Niobrara Shale, Utica Shale, Mid-Continent region and Corporate.

The following tables reflect our revenues, throughput, operating expenses and operating expenses per Mcf of throughput by segment for the years ended December 31, 2013 and 2012 (please note that revenue, throughput and operating expenses related to our equity investments (primarily in the Marcellus Shale) are excluded from the tables below as the financial results for our equity investments are reported separately. Please read “Income from Unconsolidated Affiliates” in this Results of Operations section of Management’s Discussion and Analysis of Financial Condition and Results of Operations):

	Years Ended December 31,
	2013		2012		% Change⁽¹⁾
	(In thousands, except percentages and throughput data)
Revenue:
Barnett Shale	$	433,709	$	395,467		9.7	%
Eagle Ford Shale⁽²⁾		278,282		7,232		N.M.
Haynesville Shale⁽²⁾		119,209		68,184		74.8
Marcellus Shale⁽²⁾		10,989		783		N.M.
Niobrara Shale⁽²⁾		15,095		116		N.M.
Utica Shale⁽²⁾		44,063		353		N.M.
Mid-Continent		171,875		136,312		26.1
	$	1,073,222	$	608,447		76.4	%
Throughput (Bcf)⁽³⁾:
Barnett Shale		381.3		437.3		(12.8	)%
Eagle Ford Shale		96.0		2.2		N.M.
Haynesville Shale		244.3		138.4		76.5
Marcellus Shale		372.1		256.7		45.0
Niobrara Shale		5.5		0.1		N.M.
Utica Shale		39.0		0.5		N.M.
Mid-Continent		212.2		206.5		2.8
		1,350.4		1,041.7		29.6	%

	Years Ended December 31,
	2013		2012		% Change⁽¹⁾
	(In thousands, except percentages and per Mcf data)
Operating Expenses:
Barnett Shale	$	96,926	$	101,703		(4.7	)%
Eagle Ford Shale⁽²⁾		59,059		1,604		N.M.
Haynesville Shale⁽²⁾		41,176		15,642		163.2
Marcellus Shale⁽²⁾		4,834		188		N.M.
Niobrara Shale⁽²⁾		9,090		85		N.M.
Utica Shale⁽²⁾		19,065		159		N.M.
Mid-Continent		70,609		52,979		33.3
Corporate		37,957		25,279		50.2
	$	338,716	$	197,639		71.4	%
Expenses ($ per Mcf):
Barnett Shale	$	0.25	$	0.23		8.7	%
Eagle Ford Shale		0.62		0.73		(15.1	)
Haynesville Shale		0.17		0.11		54.5
Marcellus Shale		0.91		0.63		44.4
Niobrara Shale		1.65		0.85		94.1
Utica Shale		0.49		0.31		58.1
Mid-Continent		0.33		0.26		26.9
	$	0.34	$	0.19		78.9	%

Revenues. For the years ended December 31, 2013 and 2012, revenues totaled $433.7 million and $395.5 million, respectively. The increase was primarily the result of increasing volumes under our minimum volume commitment and the full year impact of the five cents per mcf fee redetermination which was effective on July 1, 2012. Total revenue for 2013 includes $64.9 million of revenues associated with the contractual minimum volume commitment. The minimum volume revenue offset a decrease in throughput of 12.8 percent due to decreased drilling activity by Chesapeake in 2013.

Operating Expenses. For the years ended December 31, 2013 and 2012, operating expenses were $96.9 million, or $0.25 per Mcf, compared to $101.7 million, or $0.23 per Mcf, respectively. Total operating expenses decreased 4.7% consistent with the decrease in throughput. The most significant operating expenses in the Barnett Shale region are compression costs.

Depreciation and Amortization Expenses. For the years ended December 31, 2013 and 2012, depreciation expenses were $97.9 million and $93.3 million, respectively. The increase was due to capital expenditures made in this region during 2013 and 2012.

Revenues. For the year ended December 31, 2013, revenues in the Eagle Ford totaled $278.3 million and were primarily attributable to the amount of throughput on our gathering systems and the rates charged for gathering such throughput. We invested $316.0 million of capital in this region in 2013 and as a result, we expect increased revenues in 2014.

Operating Expenses. For the year ended December 31, 2013, operating expenses totaled $59.1 million, or $0.62 per Mcf. The most significant operating expenses in this region are employee compensation and compression costs. We expect our operating expenses to increase in this region in 2014 if Chesapeake increases its drilling activity.

Depreciation and Amortization Expenses. Depreciation and amortization expense for the year ended December 31, 2013, was $51.4 million and related almost entirely to depreciation of our operating assets in the region.

Revenues. For the years ended December 31, 2013 and 2012, revenues were $119.2 million and $68.2 million, respectively. An overall increase in throughput of 76.5 percent resulted from production from the Mansfield gathering system acquired in December 2012, offset by a volume decrease for the Springridge gathering system of 16.1 percent. Haynesville revenues were positively impacted by an annual rate escalation of 2.5 percent and rate redetermination of 15 percent on the Springridge gathering system, both effective January 1, 2013. Additionally, we have contractual minimum volume commitments from Chesapeake in the Haynesville Shale. Throughput for each of the years ended December 31, 2013 and 2012 was above the minimum volume commitment levels.

Operating Expenses. For the years ended December 31, 2013 and 2012, operating expenses were $41.2 million and $15.6 million, respectively. All of our operating expenses in this region increased significantly as a result of the acquisition of the Mansfield gathering system in December 2012. Operating expenses per Mcf increased primarily due to the need for additional treating services for the natural gas gathered in our Mansfield gathering system. We continue to evaluate reductions in our operating costs in this dry gas region to address the decrease in throughput caused by the low natural gas price environment.

On September 4, 2013, we sold Mid-Atlantic Gas Services, L.L.C. (“Mid-Atlantic”) to Chesapeake for net proceeds of $32.9 million. Mid-Atlantic was acquired in December 2012 and consisted of midstream assets in the Marcellus region. These assets were not part of our equity method investment in Appalachia Midstream. The net proceeds equaled our basis in the assets; thus, no gain or loss was recognized as a result of the sale.

The large majority of our assets in the Marcellus Shale are accounted for as equity investments and included in Income from Unconsolidated Affiliates. See further discussion below under “Income from Unconsolidated Affiliates” in this section of Marcellus Shale results of operations.

Income from unconsolidated affiliates. On December 29, 2011, we acquired all of the issued and outstanding equity interest in 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 average 53 percent interests in these assets are owned primarily by Statoil, Anadarko, Epsilon and Mitsui. Income from unconsolidated affiliates was $133.0 million and $67.6 million reflecting activity for the years ended December 31, 2013 and 2012, respectively. Revenues (net to our interest) for the years ended December 31, 2013 and 2012 were $234.8 million and $140.5 million, respectively. The net increase was due to throughput growth and increased construction activity in the Marcellus region where we invested $289.7 million of capital in 2013. Operating expenses on a per unit basis for the years ended December 31, 2013 and 2012 were $0.10 Mcf and $0.06 Mcf, respectively. The increase in operating expenses is consistent with the increase in revenues in the Marcellus region. The margin for these assets is strong as a result of lower operating expenses than in many other regions of the United States. These lower operating expenses are primarily due to high reservoir pressures that reduce the need for compression in the transportation of commodities. We expect our margin in the Marcellus Shale to remain strong; however, we could experience a slight decrease in our margin over time as the need for additional compression increases. The following table summarizes the results of the Appalachia Midstream assets (net to our interest) for the year ended December 31, 2013.

We acquired our ownership interest in the Niobrara Shale assets in December 2012 and own that interest through our 50 percent ownership interest in Jackalope Gas Gathering, L.L.C., in which Crestwood Niobrara LLC owns the remaining 50 percent interest. Because we operate the assets and have contractual discretion to make operating decisions for the assets, we are deemed to control the assets and thus, we consolidated 100 percent of the assets and results of operation in our financial results. We present the noncontrolling interest for these assets in Noncontrolling Interests on the condensed consolidated balance sheet and in Net Income Attributable to Noncontrolling Interests on the condensed consolidated statement of operations.

Revenues. For the year ended December 31, 2013, revenues in the Niobrara Shale region were $15.1 million and were primarily attributable to the amount of throughput on our gathering systems and the rates charged for gathering such throughput. We continue to invest significant capital in this region that is expected to drive volume growth in future periods.

Operating Expenses. For the year ended December 31, 2013, operating expenses in the Niobrara Shale region were $9.1 million. Expenses are expected to increase significantly in 2014 as construction activity increases and we prepare to provide additional gathering and processing services in this region in future periods. The most significant expenses in this region are employee compensation and compression costs.

In the CMO Acquisition, we acquired a 100 percent ownership interest in four natural gas gathering systems, a 66 percent operating interest in the Cardinal Joint Venture and a 49 percent interest in the UEO Joint Venture. Because we operate the four wholly-owned natural gas gathering systems and Cardinal Joint Venture and have contractual discretion to make operating decisions for the Cardinal Joint Venture, we are deemed to control the assets and, as a result, we consolidate 100 percent of the assets and results of operations in our financial results and reflect the ownership of the other interest owners through a noncontrolling interest in the income and equity of the investment. The UEO Joint Venture is accounted for as an equity investment because the power to direct the activities which are most significant to the UEO Joint Venture’s economic performance is shared between us and the other equity holders.

Revenues. For the year ended December 31, 2013, revenues in the Utica Shale region were $44.1 million and were primarily attributable to the amount of throughput and rates charged for such throughput on our gathering systems and gathering systems included in the Cardinal Joint Venture. We continue to invest significant capital in this region that is expected to drive volume and revenue growth in future periods.

Operating expenses. For the year ended December 31, 2013, operating expenses in the Utica Shale region were $19.1 million. The most significant operating expenses in this region are compensation and compression costs.

Income from unconsolidated affiliates. For the years ended December 31, 2013 and 2012, loss from unconsolidated affiliates was $3.8 million and $0.1 million, respectively.

Revenues. For the years ended December 31, 2013 and 2012, revenues were $171.9 million and $136.3 million, respectively. This increase was due to increased throughput of 2.5 percent as drilling activity increased in this liquids-rich region, a 2.5 percent annual fee escalation and a 15 percent fee increase due to annual contractual fee redetermination.

Operating Expenses. For the years ended December 31, 2013 and 2012, operating expenses were $70.6 million and $53.0 million, respectively. Operating expenses increased primarily due to added compression in anticipation of additional future throughput.

Income from unconsolidated affiliates. As part of the CMO Acquisition, we acquired a 33.33 percent equity interest in Ranch Westex JV LLC, which we own jointly with Regency Energy Partners, LP and Anadarko Pecos Midstream LLC. For the years ended December 31, 2013 and 2012, income (loss) from unconsolidated affiliates was $1.2 million and $(0.1) million, respectively.

Operating Expenses. For the years ended December 31, 2013 and 2012, operating expenses were $38.0 million and $25.3 million, respectively. The increase in operating expenses resulted from additional technical resources to support the assets acquired in 2012.

General and Administrative Expense. For the years ended December 31, 2013 and 2012, general and administrative expenses were $104.3 million and $67.6 million, respectively, representing an increase of 54.3 percent. This increase is primarily attributable to additional overhead expenses resulting from the increased scale of our operations following the CMO Acquisition, additional expense from equity-based, long-term incentive compensation influenced by the increase in our unit price, as well as transition costs as we developed an independent back office infrastructure.

Interest Expense. Interest expense for the year ended December 31, 2013 was $116.8 million, which was net of $43.9 million of capitalized interest. Interest expense was $64.7 million for the year ended December 31, 2012, which was net of $14.6 million of capitalized interest. The increase is related to interest expense on the 2023 Notes, issued in December 2012 and Additional Notes, issued August 2013. We also incurred interest expenses on borrowings under our revolving credit facility and our outstanding senior notes. Interest expense also includes commitment fees on the unused portion of our credit facility and amortization of debt issuance costs.

Income Tax Expense. Income tax expense for the years ended December 31, 2013 and 2012 was $5.2 million and $3.2 million, respectively, and was attributable to franchise taxes in the state of Texas. We and our 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.

The following tables reflect our revenues, throughput, operating expenses and operating expenses per Mcf of throughput by segment for the years ended December 31, 2012 and 2011 (please note that revenue, throughput and operating expenses related to our equity investments (primarily in the Marcellus Shale) are excluded from the tables below as the financial results for our equity investments are reported separately. Please read “Income from Unconsolidated Affiliates” in this Results of Operations section of Management’s Discussion and Analysis of Financial Condition and Results of Operations):

	Years Ended December 31,
	2012		2011		% Change⁽¹⁾
	(In thousands, except percentages and throughput data)
Revenue:
Barnett Shale	$	395,467	$	361,843		9.3	%
Eagle Ford Shale⁽²⁾		7,232		—		N.M.
Haynesville Shale⁽²⁾		68,184		93,107		(26.8	)
Marcellus Shale⁽²⁾		783		—		N.M.
Niobrara Shale⁽²⁾		116		—		N.M.
Utica Shale⁽²⁾		353		—		N.M.
Mid-Continent		136,312		110,979		22.8
	$	608,447	$	565,929		7.5	%
Throughput (Bcf):
Barnett Shale		437.3		395.4		10.6	%
Eagle Ford Shale		2.2		—		N.M.
Haynesville Shale		138.4		197.5		(30.0	)
Marcellus Shale		256.7		—		N.M.
Niobrara Shale		0.1		—		N.M.
Utica Shale		0.5		—		N.M.
Mid-Continent		206.5		201.4		2.5
		1,041.7		794.3		31.1	%

	Years Ended December 31,
	2012		2011		% Change⁽¹⁾
	(In thousands, except percentages and per Mcf data)
Operating Expenses:
Barnett Shale	$	101,703	$	94,009		8.2	%
Eagle Ford Shale⁽²⁾		1,604		—		N.M.
Haynesville Shale⁽²⁾		15,642		18,057		(13.4	)
Marcellus Shale⁽²⁾		188		—		N.M.
Niobrara Shale⁽²⁾		85		—		N.M.
Utica Shale⁽²⁾		159		—		N.M.
Mid-Continent		52,979		47,749		11.0
Corporate		25,279		17,036		48.4
	$	197,639	$	176,851		11.8	%
Expenses ($ per Mcf):
Barnett Shale	$	0.23	$	0.24		(4.2	)%
Eagle Ford Shale		0.73		—		N.M.
Haynesville Shale		0.11		0.09		22.2
Marcellus Shale		0.63		—		N.M.
Niobrara Shale		0.85		—		N.M.
Utica Shale		0.31		—		N.M.
Mid-Continent		0.26		0.24		8.3
	$	0.19	$	0.22		(13.6	)%

Revenues. For the years ended December 31, 2012 and 2011, revenues were $395.5 million and $361.8 million, respectively. The increase was primarily the result of increased throughput of 10.6 percent due to additional wells connected in 2011 and the first half of 2012. Additionally, the Barnett Shale fees increased five cents per mcf effective July 1, 2012, as a result of fee redetermination.

We have contractual minimum volume commitments from Chesapeake and Total in the Barnett Shale. Throughput in the Barnett Shale during the current year was above the minimum volume commitment level. Because throughput in the Barnett Shale during 2011 was below contractual minimum volume commitment levels, we recognized revenue related to the volume shortfall of $17.4 million for the year ended December 31, 2011.

Operating Expenses. For the years ended December 31, 2012 and 2011, operating expenses were $101.7 million and $94.0 million, respectively. As throughput increased, operating expenses have increased in order to support the additional throughput. Operating expenses per Mcf decreased slightly from 2011 to 2012.

Depreciation and Amortization Expenses. For the years ended December 31, 2012 and 2011, depreciation expenses were $93.3 million and $77.0 million. The increase was due to capital expenditures made in this region during 2011 and 2012.

We acquired the Eagle Ford Shale assets in December 2012. For the twelve-day period from closing the CMO Acquisition on December 20, 2012 through December 31, 2012, revenues and operating expenses were $7.2 million and $1.6 million, respectively.

Revenues. For the years ended December 31, 2012 and 2011, revenues were $68.2 million and $93.1 million, respectively. Revenues were down 26.8 percent due to a volume decrease on the Springridge gathering system, offset partially by a 2.5 percent annual fee escalation and additional production from the Mansfield gathering system acquired in December 2012. Additionally, we have contractual minimum volume commitment from Chesapeake in the Haynesville Shale. Throughput during the current year was above the minimum volume commitment levels.

Operating Expenses. For the years ended December 31, 2012 and 2011, operating expenses were $15.6 million and $18.1 million, respectively. We have reduced operating expense in the Haynesville Shale in response to the reduction in throughput in this region; however, in the first half of 2012 we had fixed costs in this area which caused the expense per Mcf to increase temporarily.

Revenues and expenses in the Marcellus Shale reflect only the results of the Marcellus gathering systems acquired in December 2012. For the twelve-day period from closing the CMO Acquisition on December 20, 2012 through December 31, 2012, revenues and expenses were $0.8 million and $0.2 million, respectively. The majority of our assets in the Marcellus Shale are accounted for as equity investments and included in Income from Unconsolidated Affiliates. See further discussion below under “Income from Unconsolidated Affiliates” in this section of Marcellus Shale results of operations.

We acquired a 50 percent ownership interest in the Niobrara Shale assets in December 2012. Because we operate the assets and have contractual discretion to make operating decisions for the assets, we are deemed to control the assets and thus, we consolidated 100 percent of the assets and results of operation in our financial results. We present the noncontrolling interest for these assets in Noncontrolling Interests on the condensed consolidated balance sheet and in Net Income Attributable to Noncontrolling Interests on the condensed consolidated statement of operations. For the twelve-day period from closing the CMO Acquisition on December 20, 2012 through December 31, 2012, revenues and operating expenses in the Niobrara Shale were $0.1 million and $0.1 million, respectively.

In the CMO Acquisition, we acquired a 100 percent ownership interest in four natural gas gathering systems, a 66 percent operating interest in the Cardinal Joint Venture and a 49 percent interest in the UEO Joint Venture. Because we operate the four wholly-owned natural gas gathering systems and Cardinal Joint Venture and have contractual discretion to make operating decisions for the Cardinal Joint Venture, we are deemed to control the assets and thus, we consolidated 100 percent of the assets and results of operations in our financial results and reflect the ownership of the other interest owners through a noncontrolling interest in the income and equity of the investment. The UEO Joint Venture is accounted for as an equity investment because the power to direct the activities which are most significant to the UEO Joint Venture’s economic performance is shared between us and the other equity holders. For the twelve-day period from closing the CMO Acquisition on December 20, 2012 through December 31, 2012, revenues and operating expenses in the Utica Shale were $0.4 million and $0.2 million, respectively.

Revenues. For the years ended December 31, 2012 and 2011, revenues were $136.3 million and $111.0 million, respectively. This increase was due to increased throughput of 2.5 percent as drilling activity increased in this liquids-rich region, a 2.5 percent annual fee escalation and a 15 percent fee increase due to annual contractual fee redetermination.

Operating Expenses. For the years ended December 31, 2012 and 2011, operating expenses were $53.0 million and $47.7 million, respectively. Operating expenses increased due to added compression to support additional throughput.

Operating Expenses. For the years ended December 31, 2012 and 2011, operating expenses were $25.3 million and $17.0 million, respectively. The increase in operating expenses resulted from additional technical resources to support the assets we acquired in 2011.

General and Administrative Expense. For the years ended December 31, 2012 and 2011, general and administrative expenses were $67.6 million and $40.4 million, respectively, representing an increase of 67.3 percent. This increase is primarily attributable to additional overhead expenses resulting from the increased scale of our operations, additional expense from equity-based, long-term incentive compensation influenced by the recent increase in our unit

price, one-time transition costs as we develop an independent back office infrastructure and $15.0 million of transaction costs related to the CMO Acquisition.

Interest Expense. Interest expense for the year ended December 31, 2012 was $64.7 million, which was net of $14.6 million of capitalized interest. Interest expense was $14.9 million for the year ended December 31, 2011, which was net of $9.5 million of capitalized interest. The increase is related to interest expense on the $750 million of senior notes issued in January 2012 and $1.4 billion of senior notes issued in December 2012. We incurred interest expenses on borrowings under our revolving credit facility and our senior notes issued in April 2011. Interest expense also includes commitment fees on the unused portion of our credit facility and amortization of debt issuance costs.

Income Tax Expense. Income tax expense for the years ended December 31, 2012 and 2011 was $3.2 million and $3.3 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.

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 (Deficit). 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, 2013 and 2012, we had working capital deficits of $48.5 million and $39.5 million, respectively, due to our capital intensive business that requires significant investment in new midstream operating assets and to maintain and improve existing facilities.

Cash Flows. Net cash provided by (used in) operating activities, investing activities and financing activities of the Partnership for the year ended December 31, 2013 and 2012 were as follows:

Operating Activities. Net cash provided by operating activities was $564.0 million for the year ended December 31, 2013 compared to $318.1 million for the year ended December 31, 2012. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items such as depreciation, amortization and gains or losses on sales of fixed assets. See additional discussion in the Results of Operations section above in the Management’s Discussion and Analysis. The changes in cash flow are also impacted by timing impacts on working capital accounts.

Investing Activities. Net cash used in investing activities for the year ended December 31, 2013 decreased $1.1 billion compared to the prior year. Approximately $1.6 billion of cash was used in investing activities during 2013. This amount included approximately $1.1 billion in additions to property, plant, and equipment. It also includes $572.4 million of additional investment in our unconsolidated affiliates.

Financing Activities. Net cash provided by financing activities was $944.7 million for the year ended December 31, 2013 compared to $2.4 billion for the year ended December 31, 2012. This decrease was primarily attributable to the proceeds from the issuance of debt and equity in 2012 to fund the CMO Acquisition.

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.

Revolving Credit Facility. On May 13, 2013, we amended and restated our existing senior secured revolving credit facility. The amended and restated revolving credit facility matures in May 2018 and includes aggregate revolving commitments of $1.75 billion, including a sub-limit of $100 million for same-day swing line advances and a sub-limit of $200 million for letters of credit. In addition, the revolving credit facility’s accordion feature allows us to increase the available borrowing capacity under the facility up to $2.0 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 revolving credit facility. As of December 31, 2013, we had approximately $343.5 million of borrowings outstanding under our revolving credit facility. As of December 31, 2012, there were no borrowings outstanding.

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 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 0.50 percent to 1.50 percent per annum, according to our leverage ratio (as defined in the agreement), or (ii) the Eurodollar rate plus a margin that varies from 1.50 percent to 2.50 percent per annum, according to our 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 0.375 percent per annum while we are subject to the leverage-based pricing grid, according to our leverage ratio and (b) 0.15 percent to 0.30 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 or restricted payments; modify certain material agreements; 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 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 $50 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 and allows for us to release all collateral securing the revolving credit facility if we reach investment grade status. The revolving credit facility agreement also requires us to maintain a consolidated leverage ratio of 5.5 to 1.0 (or 5.0 to 1.0 after we have released all collateral upon achieving investment grade status). We were in compliance with all covenants under the agreement at December 31, 2013.

Senior Notes. On April 19, 2011, we and ACMP Finance Corp. a wholly owned subsidiary of Access 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”). 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 $8.2 million are being amortized over the life of the 2021 Notes.

On January 11, 2012, we and ACMP Finance Corp. 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 $13.8 million are being amortized over the life of the 2022 Notes.

On December 19, 2012, we and ACMP Finance Corp. completed a public offering of $1.4 billion in aggregate principal amount of 4.875 percent senior notes due 2023 (the “2023 Notes”). We used a portion of the net proceeds to fund a portion of the purchase price for the CMO Acquisition, and the balance to repay borrowings outstanding under our revolving credit facility. Debt issuance costs of $25.8 million are being amortized over the life of the 2023 Notes.

On August 14, 2013, we issued $400 million in aggregate principal amount of additional 5.875 percent senior notes due 2021 (the “Additional Notes”). The Additional Notes are additional to the $350 million of 2021 Notes initially issued on April 19, 2011 and are fully fungible with, rank equally with and form a single series with the 2021 Notes. The Additional Notes were issued at a price of 101.5 percent of the principal amount plus accrued interest from April 15, 2013, resulting in net proceeds of $400.8 million, which was used for general partnership purposes, including funding working capital, repayment of indebtedness and funding our capital expenditure program. Debt issuance costs of $5.8 million are being amortized over the life of the Additional 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. 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, 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 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.

The 2023 Notes will mature on May 15, 2023, and interest is payable on May 15 and November 15 of each year. We have the option to redeem all or a portion of the 2023 Notes at any time on or after December 15, 2017, at the redemption price specified in the indenture relating to the 2023 Notes, plus accrued and unpaid interest. We may also redeem the 2023 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 December 15, 2017. In addition, we may redeem up to 35 percent of the 2023 Notes prior to December 15, 2015 under certain circumstances with the net cash proceeds from certain equity offerings.

The 2023 Notes, 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 our 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 2023 Notes, 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 indentures, has occurred or is continuing, many of these covenants will terminate.

We, as the parent company, have no independent assets or operations. Our operations are conducted by our subsidiaries through our primary operating company subsidiary, Access MLP Operating, L.L.C., our direct 100 percent owned subsidiary. Access MLP Operating, and each of our other direct and indirect 100 percent owned subsidiaries is a guarantor, other than ACMP Finance Corp., our indirect 100 percent owned subsidiary whose sole purpose is to act as co-issuer of any debt securities. The guarantees 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 applicable indenture. There are no significant restrictions on

our ability or the ability of any guarantor to obtain funds from our or its respective subsidiaries by dividend or loan. None of our assets or the assets of any guarantor represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.

Equity Issuance. On August 2, 2013, we entered into an Equity Distribution Agreement under which we may offer and sell common units, in amounts, at prices and on terms to be determined by market conditions and other factors, having an aggregate market value of up to $300 million. We are under no obligation to issue equity under the Equity Distribution Agreement. For the year ended December 31, 2013, we sold an aggregate of 0.9 million common units under the Equity Distribution Agreement for aggregate gross proceeds of approximately $50.1 million and an approximate $1.0 million capital contribution from our general partner to maintain its two percent general partner interest. We used the proceeds for general partnership purposes.

On April 2, 2013, we completed an equity offering of 10.35 million common units, including 1.35 million common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price of $39.86 per common unit. We received offering proceeds (net of underwriting discounts and commissions) of $399.8 million from the equity offering, including proceeds from the underwriters’ exercise of their option to purchase additional common units and an approximate $8.4 million capital contribution from our general partner to maintain its two percent general partner interest. The proceeds were used for general partnership purposes, including repayment of amounts outstanding under our revolving credit facility.

On December 18, 2012, we completed an equity offering of 18.4 million common units, including 2.4 million common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price of $32.15 per common unit.

We received offering proceeds (net of underwriting discounts, commissions and offering expenses) of approximately $569.3 million from the equity offering, including proceeds from the underwriters’ exercise of their option to purchase additional common units. We used the net proceeds to pay a portion of the purchase price for the CMO Acquisition.

Subscription Agreement. On December 20, 2012, we sold 5.9 million Class B units to each of the GIP II Entities and Williams and 5.6 million Class C units to each of the GIP II Entities and Williams, in each case pursuant to the subscription agreement. We received aggregate proceeds of approximately $712.1 million in exchange for the sale of Class B units and Class C units, inclusive of the capital contribution made by our general partner to maintain its two percent interest in us following the issuance of common, Class B and Class C units.

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:

For the years ended December 31, 2013 and 2012, growth capital expenditures totaled $1.5 billion and $734.9 million, respectively. The 2013 and 2012 amounts include $671.4 million and $384.4 million, respectively, of capital expenditures made as part of our unconsolidated affiliates that are accounted for as equity investments. Maintenance capital expenditures totaled $110.0 million and $75.2 million for the years ended December 31, 2013 and 2012, respectively, an increase of 46.3 percent. 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.

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 ended December 31, 2013 and 2012:

Contractual Obligations. At December 31, 2013, our contractual obligations included:

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.

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 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:

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.

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.

An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. We consolidate a VIE when we have both the power to direct the activities that most significantly impact the activities of the VIE and the right to receive benefits or the obligation to absorb losses of the entity that could be potentially significant to the VIE. We continually monitor both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change.

Certain statements and information in this annual report 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:

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

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.

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, compression and processing 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 or processing agreements with us. Not all of our counterparties under our gas gathering or processing 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 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, 2013, a 125 basis point increase in the interest rate would have resulted in a $35.6 million decrease in net income.

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 and processing 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 any minimum volume commitments, fee redetermination provisions and cost of service provisions in our commercial agreements with producers, 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.

It is the responsibility of the management of Access Midstream Partners, L.P. to establish and maintain adequate internal control over financial reporting (as defined in Rules 13a — 15(f) and 15d — 15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our 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 our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2013, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in 1992 Internal Control — Integrated Framework. Based on our assessment, we concluded that, as of December 31, 2013, our internal control over financial reporting was effective.

The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.

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

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in partners’ capital and of cash flows present fairly, in all material respects, the financial position of Access Midstream Partners, L.P. and its subsidiaries (the "Partnership") at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 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, 2013, based on criteria established in Internal Control - Integrated Framework 1992 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. 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 financial 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.

Prior to December 2012, as discussed in Notes 5 and 6 to the accompanying consolidated financial statements, Access Midstream Partners, L.P. earned substantially all of its revenues and had 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.

	December 31, 2013			December 31, 2012
	($ in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	17,229		$	64,994
Accounts receivable		222,409			133,543
Prepaid expenses		10,182			13,978
Other current assets		8,111			7,251
Total current assets		257,931			219,766
Property, plant and equipment:
Gathering systems		5,974,940			5,125,746
Other fixed assets		175,411			96,916
Less: Accumulated depreciation		(859,551	)		(590,614	)
Total property, plant and equipment, net		5,290,800			4,632,048
Investments in unconsolidated affiliates		1,936,603			1,297,811
Intangible customer relationships, net		372,391			355,217
Deferred loan costs, net		59,721			56,258
Total assets	$	7,917,446		$	6,561,100
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	37,520		$	47,987
Accrued liabilities		268,952			211,274
Total current liabilities		306,472			259,261
Long-term liabilities:
Long-term debt		3,249,230			2,500,000
Other liabilities		8,954			5,333
Total long-term liabilities		3,258,184			2,505,333
Commitments and contingencies (Note 12)
Partners’ capital:
Common units (177,801,147 and 97,324,453 issued and outstanding at December 31, 2013 and 2012, respectively)		3,343,145			2,188,241
Subordinated units (zero and 69,076,122 issued and outstanding at December 31, 2013 and 2012)		—			834,001
Class B units (12,424,358 and 11,858,050 issued and outstanding at December 31, 2013 and 2012, respectively)		318,472			273,858
Class C units (11,199,268 and 11,199,268 issued and outstanding at December 31, 2013 and 2012, respectively)		322,896			295,551
General partner interest		114,393			93,182
Total partners’ capital attributable to Access Midstream Partners, L.P.		4,098,906			3,684,833
Noncontrolling interest		253,884			111,673
Total partners’ capital		4,352,790			3,796,506
Total liabilities and partners’ capital	$	7,917,446		$	6,561,100

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

	Year Ended December 31, 2013			Year Ended December 31, 2012			Year Ended December 31, 2011
	($ in thousands, except per unit data)
Revenues	$	1,073,222		$	608,447		$	565,929
Operating expenses
Operating expenses		338,716			197,639			176,851
Depreciation and amortization expense		296,179			165,517			136,169
General and administrative expense		104,332			67,579			40,380
Other operating (income) expense		2,092			(766	)		739
Total operating expenses		741,319			429,969			354,139
Operating income		331,903			178,478			211,790
Other income (expense)
Income from unconsolidated affiliates		130,420			67,542			433
Interest expense (Note 11)		(116,778	)		(64,739	)		(14,884	)
Other income		827			320			287
Income before income tax expense		346,372			181,601			197,626
Income tax expense		5,223			3,214			3,289
Net income		341,149			178,387			194,337
Net income (loss) attributable to noncontrolling interests		5,124			(68	)		—
Net income attributable to Access Midstream Partners, L.P.	$	336,025		$	178,455		$	194,337
Limited partner interest in net income
Net income attributable to Access Midstream Partners, L.P.	$	336,025		$	178,455		$	194,337
Less general partner interest in net income		(40,681	)		(8,481	)		(5,070	)
Limited partner interest in net income	$	295,344		$	169,974		$	189,267
Net income per limited partner unit – basic and diluted
Common units	$	1.01		$	1.11		$	1.37
Subordinated units⁽¹⁾	$	0.93		$	1.14		$	1.37

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

	Year Ended December 31, 2013			Year Ended December 31, 2012			Year Ended December 31, 2011
	($ in thousands)
Cash flows from operating activities:
Net income	$	341,149		$	178,387		$	194,337
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		296,179			165,517			136,169
Income from unconsolidated affiliates		(130,420	)		(67,542	)		(433	)
Other non-cash items		20,577			8,296			6,486
Distribution of earnings received from unconsolidated affiliates		82,871			—			—
Changes in assets and liabilities:
(Increase) decrease in accounts receivable		(97,507	)		18,484			31,501
(Increase) decrease in other assets		2,244			(9,925	)		(292	)
Increase (decrease) in accounts payable		(10,492	)		8,800			11,258
Increase in accrued liabilities		59,361			16,113			19,990
Net cash provided by operating activities		563,962			318,130			399,016
Cash flows from investing activities:
Additions to property, plant and equipment		(1,058,599	)		(350,500	)		(418,834	)
Acquisition of gathering system assets		—			(2,160,000	)		—
Investment in unconsolidated affiliates		(572,370	)		(185,039	)		(600,000	)
Proceeds from sale of assets		74,551			9,574			1,730
Net cash used in investing activities		(1,556,418	)		(2,685,965	)		(1,017,104	)
Cash flows from financing activities:
Proceeds from long-term debt borrowings		2,015,700			1,387,800			1,576,700
Payments on long-term debt borrowings		(1,672,200	)		(2,100,700	)		(1,112,900	)
Proceeds from issuance of common units		449,312			569,255			—
Proceeds from issuance of Class B units		—			343,000			—
Proceeds from issuance of Class C units		—			343,000			—
Proceeds from issuance of senior notes		414,094			2,150,000			350,000
Distributions to unit holders		(389,128	)		(251,720	)		(200,897	)
Capital contributions from noncontrolling interests		151,976			—			—
Payments on capital lease obligations		(3,552	)		—			—
Payments on leasehold improvement financing		(17,798	)		—			—
Debt issuance costs		(12,414	)		(39,626	)		(11,332	)
Initial public offering costs		—			—			(1,280	)
Other adjustments		8,701			31,798			3
Net cash provided by financing activities		944,691			2,432,807			600,294
Net increase (decrease) in cash and cash equivalents		(47,765	)		64,972			(17,794	)
Cash and cash equivalents, beginning of period		64,994			22			17,816
Cash and cash equivalents, end of period	$	17,229		$	64,994		$	22
Supplemental disclosure of non-cash investing activities:
Changes in accounts payable and other liabilities related to purchases of property, plant and equipment	$	7,434		$	60,427		$	8,589
Changes in other liabilities related to asset retirement obligations	$	(1,314	)	$	(133	)	$	324
Property, plant and equipment acquired under capital lease	$	(9,370	)	$	—		$	—
Property, plant and equipment acquired through leasehold improvement financing	$	(17,798	)	$	—		$	—
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, net of capitalized interest	$	39,939		$	30,292		$	16,957
Supplemental disclosure of cash payments for taxes	$	3,300		$	2,900		$	2,830

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

	Partners’ Equity
	Limited Partners
	Common			Subordinated			Class B			Class C			General Partner			Non controlling Interest			Total
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
Net income		90,822			78,736			214			202			8,481			(68	)		178,387
Distribution to unitholders		(130,204	)		(113,976	)		—			—			(7,540	)		—			(251,720	)
Contributions from noncontrolling interest owners		—			—			—			—			—			111,741			111,741
Non-cash equity based compensation		3,695			—			—			—			—			—			3,695
Issuance of common units		569,255			—			—			—			—			—			569,255
Issuance of Class B units		—			—			331,148			—			—			—			331,148
Issuance of Class C units		—			—			—			331,115			—			—			331,115
Issuance of general partner interests		—			—			—			—			49,841			—			49,841
Beneficial conversion feature of Class B and Class C units		95,073			—			(58,328	)		(36,745	)		—			—			—
Amortization of beneficial conversion feature of Class B and Class C units		(1,803	)		—			824			979			—			—			—
Other adjustments		(101	)		—			—			—			—			—			(101	)
Balance at December 31, 2012	$	2,188,241		$	834,001		$	273,858		$	295,551		$	93,182		$	111,673		$	3,796,506
Net income		206,236			54,479			18,055			16,574			40,681			5,124			341,149
Distributions to unitholders		(241,080	)		(96,879	)		—			(21,699	)		(29,470	)		—			(389,128	)
Conversion of subordinated units to common units		791,601			(791,601	)		—			—			—			—			—
Contributions from noncontrolling interest owners		—			—			—			—			—			137,087			137,087
Non-cash equity based compensation		7,864			—			—			—			—			—			7,864
Issuance of common units		449,312			—			—			—			—			—			449,312
Issuance of general partner interests		—			—			—			—			10,000			—			10,000
Beneficial conversion feature of Class B units		1,317			—			(1,317	)		—			—			—			—
Amortization of beneficial conversion Feature of Class B and Class C units		(60,346	)		—			27,876			32,470			—			—			—
Balance at December 31, 2013	$	3,343,145		$	—		$	318,472		$	322,896		$	114,393		$	253,884		$	4,352,790

Basis of presentation. Access 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. The Partnership is the industry’s largest gathering and processing master limited partnership as measured by throughput volume. The Partnership’s assets are located in Arkansas, Kansas, Louisiana, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia and Wyoming. The Partnership provides gathering, treating and compression services to Chesapeake Energy Corporation (“Chesapeake”), Total Gas and Power North America, Inc. (“Total”), Statoil ASA (“Statoil”), Anadarko Petroleum Corporation (“Anadarko”), Mitsui & Co., Ltd. (“Mitsui”) and other producers under long-term, fixed-fee contracts.

For purposes of these financial statements, the “GIP I Entities” refers to, collectively, GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P. and GIP-C Holding (CHK), L.P., the “GIP II Entities” refers to certain entities affiliated with Global Infrastructure Investors II, LLC, and “GIP” refers to the GIP I Entities and their affiliates and the GIP II Entities, collectively. “Williams” refers to The Williams Companies, Inc. (NYSE: WMB).

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.

Certain reclassifications have been made to prior period amounts to conform to the current period financial statement presentation.

GIP II Entities acquisition. During the second quarter of 2012, the GIP II Entities acquired Chesapeake’s 50 percent interest in the Partnership’s general partner and all of the common units and subordinated units in the Partnership that were previously held by Chesapeake. The remaining 50 percent interest in the Partnership’s general partner continued to be owned by the GIP I Entities.

Marcellus acquisition. On December 29, 2011, the Partnership acquired from CMD, all of the issued and outstanding equity interests in Appalachia Midstream Services, L.L.C. (“Appalachia Midstream”) for total consideration 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 549 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”). Appalachia Midstream operates the assets under 15-year fixed fee gathering agreements. The gathering agreements include significant acreage dedications and cost of service mechanisms. EBITDA exceeded the $100 million and $150 million targets in 2012 and 2013 and no additional revenue related to the commitment was recognized.

CMO acquisition. On December 20, 2012, the Partnership acquired from Chesapeake Midstream Development, L.P. (“CMD”), a wholly owned subsidiary of Chesapeake, and certain of CMD’s affiliates, 100 percent of the issued and outstanding equity interests in Chesapeake Midstream Operating, L.L.C. (“CMO”) for total consideration of $2.16 billion (the “CMO Acquisition”). As a result of the CMO Acquisition, the Partnership owns certain midstream assets in the Eagle Ford, Utica and Niobrara regions. The CMO Acquisition also extended the Partnership’s existing assets and operations in the Haynesville, Marcellus and Mid-Continent regions. The acquired assets included, in the aggregate, approximately 1,675 miles of pipeline and 4.3 million (gross) dedicated acres as of the date of the acquisition. The Partnership also

assumed various gas gathering and processing agreements associated with the assets that have terms ranging from 10 to 20 years and that, in certain cases, include cost of service or fee redetermination mechanisms.

Equity Issuance. On August 2, 2013, the Partnership entered into an Equity Distribution Agreement (“ATM”) under which it may offer and sell common units, in amounts, at prices and on terms to be determined by market conditions and other factors, having an aggregate market value of up to $300 million. The Partnership is under no obligation to issue equity under the ATM. For the year ended December 31, 2013, the Partnership sold an aggregate of 0.9 million common units under the ATM for aggregate gross proceeds of approximately $50.1 million and an approximate $1.0 million capital contribution from the Partnership’s general partner to maintain its two percent general partner interest. The Partnership used the proceeds for general partnership purposes.

On April 2, 2013, the Partnership completed an equity offering of 10.35 million common units, including 1.35 million common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price of $39.86 per common unit.

The Partnership received offering proceeds (net of underwriting discounts and commissions) of $399.8 million from the equity offering, including proceeds from the underwriters’ exercise of their option to purchase additional common units, plus an approximate $8.4 million capital contribution from the Partnership’s general partner to maintain its two percent general partner interest. The proceeds were used for general partnership purposes, including repayment of amounts outstanding under the Partnership’s revolving credit facility.

On December 18, 2012, the Partnership completed an equity offering of 18.4 million common units (such amount includes 2.4 million common units issued pursuant to the exercise of the underwriters’ over-allotment option) representing limited partner interest in the Partnership, at a price of $32.15 per common unit.

The Partnership received gross offering proceeds (net of underwriting discounts, commissions and offering expenses) from the equity offering of approximately $569.3 million, including the exercise of the option to purchase additional units. The Partnership used the net proceeds to pay a portion of the purchase price for the CMO Acquisition.

Subscription Agreement. On December 20, 2012, the Partnership sold 5.9 million Class B units to each of the GIP II Entities and Williams and 5.6 million Class C units to each of the GIP II Entities and Williams, in each case pursuant to the subscription agreement. The Partnership received aggregate proceeds of approximately $712.1 million in exchange for the sale of Class B units and Class C units, inclusive of the capital contribution made by its general partner to maintain its 2.0 percent interest in the Partnership following the issuance of common, Class B and Class C units.

The results of operations presented and discussed in this annual report include results of operations from CMO for the twelve-day period from closing of the CMO Acquisition on December 20, 2012 through December 31, 2012.

Williams Acquisition. Concurrently with the CMO Acquisition, the GIP I Entities sold to Williams 34,538,061 of the Partnership’s subordinated units and 50% of the outstanding equity interests in Access Midstream Ventures, L.L.C., the sole member of the Partnership’s general partner (“Access Midstream Ventures”), for cash consideration of approximately $1.8 billion (the “Williams Acquisition”). The Partnership did not receive any cash proceeds from the Williams Acquisition. As a result of the closing of the Williams Acquisition, the GIP II Entities and Williams together own and control the Partnership’s general partner and the GIP I Entities no longer have any ownership interest in the Partnership or its general partner.

The following table summarizes common, subordinated, Class B, Class C and general partner units issued during the years ended December 31, 2013, 2012 and 2011:

	Limited Partner Units
	Common		Subordinated			Class B		Class C		General Partner Interests		Total
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
Long-term incentive plan awards		47,810		—			—		—		976		48,786
December 2012 equity issuance		18,400,000		—			11,858,050		11,199,268		846,068		42,303,386
Balance at December 31, 2012		97,324,453		69,076,122			11,858,050		11,199,268		3,866,488		193,324,381
Long-term incentive plan awards		98,242		—			—		—		2,006		100,248
April 2013 equity issuance		10,350,000		—			—		—		211,224		10,561,224
Conversion of subordinated units to common units		69,076,122		(69,076,122	)		—		—		—		—
ATM equity issuance		952,330		—			—		—		19,435		971,765
Paid-in-kind Class B unit distributions		—		—			566,308		—		11,557		577,865
Balance at December 31, 2013		177,801,147		—			12,424,358		11,199,268		4,110,710		205,535,483

Holdings of partnership equity. At December 31, 2013, the GIP II Entities held 2,055,355 notional general partner units representing a 1.0 percent general partner interest in the Partnership, 50 percent of the Partnership’s incentive distribution rights, 52,342,727 common units, 6,212,179 Class B units and 5,599,634 Class C units. The GIP II Entities’ ownership represents an aggregate 31.2 percent limited partner interest in the Partnership. Williams held 2,055,355 notional general partner units representing a 1.0 percent general partner interest in the Partnership, 50.0 percent of the Partnership’s incentive distribution rights, 34,538,061 common units, 6,212,179 Class B units and 5,599,634 Class C units. Williams ownership represents an aggregate 22.6 percent limited partner interest in the Partnership. The public held 90,920,359 common units, representing a 44.2 percent limited partner interest in the Partnership.

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. 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 $17.2 million and $65.0 million of cash and cash equivalents as of December 31, 2013 and 2012, 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, 2013 and 2012, book overdrafts of $25.1 million and $30.0 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, 2013 and 2012, the Partnership had no allowance for doubtful accounts.

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.

Depreciation. 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. Amortization of assets recorded under capital leases is included in depreciation expense.

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.

Equity Method Investments. The equity method of accounting is used to account for the Partnership’s interest in Utica East Ohio Midstream LLC and Ranch Westex JV, LLC, which the Partnership acquired as part of the CMO Acquisition. The equity method is also used to account for the Partnership’s various ownership interests in 10 gas gathering systems in the Marcellus Shale. See Note 1 – Description of Business and Basis of Presentation for more information on the acquisitions.

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 11 — 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. Prior to the CMO Acquisition, the Partnership’s operations were organized into a single business segment. As a result of the CMO Acquisition, the Partnership added in three new operating regions. Effective January 1, 2013, the Partnership’s chief operating decision maker began to measure performance and allocate resources based on geographic segments. The Partnership’s operations are divided into eight operating segments: Barnett Shale, Eagle Ford Shale, Haynesville Shale, Marcellus Shale, Niobrara Shale, Utica Shale, Mid-Continent region and Corporate.

Revenue Recognition. In 2013, the Partnership derived the majority of its revenues through gas gathering agreements with Chesapeake and Total. Pursuant to their respective 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 and December 31, 2017 for the Springridge and Mansfield systems, respectively. 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, compression and processing of natural gas. Revenues are recognized when the service is performed and is based upon non-regulated rates and the related gathering, treating, compression and processing 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, 2013 and 2012.

Equity Based Compensation. Certain employees of the Partnership’s general partner receive equity-based compensation through the Partnership’s equity-based compensation programs. The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. This value is amortized over the vesting period, which is generally four years from the date of grant.

Certain key members of management have been designated as participants in the Management Incentive Compensation Plan which is made up of two components. The first component is an annual cash bonus based on “excess” cash distributions made by the Partnership above a specified target amount with respect to each fiscal quarter during which the award is outstanding. The second component is based on an increase in value of the Partnership’s common units at the end of a specified five-year period beginning on the award commencement date.

Included in operating expense, general and administrative expense, and income from unconsolidated affiliates is total equity-based compensation of $35.0 million, $9.0 million and $3.8 million for the Partnership during the years ended December 31, 2013, 2012 and 2011, respectively.

The LTIP provides for an aggregate of 3.5 million 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. As of December 31, 2013, there was $33.5 million of unrecognized compensation expense attributable to the LTIP, of which $29.7 million is expected to be recognized over a four year period.

The following table summarizes LTIP award activity for the year ended December 31, 2013:

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 and Appalachia Midstream is 15 years and 20 years for the CMO Acquisition. As of December 31, 2013, the carrying value of the Partnership’s intangible assets was $418.4 million, net of $46.0 of accumulated amortization. The Partnership estimates that it will record $22.8 million of intangible asset amortization for each of the next five years. As of December 31, 2012, the carrying value of the Partnership’s intangible assets was $377.8 million, net of $22.6 million of accumulated amortization. Amortization expense was $24.0 milllion, $11.3 million and $11.3 million for the years ended December 31, 2013, 2012 and 2011, respectively, for the Partnership.

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. 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.

Variable Interest Entities (VIEs). An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. We consolidate a VIE when we have both the power to direct the activities that most significantly impact the activities of the VIE and the right to receive benefits or the obligation to absorb losses of the entity that could be potentially significant to the VIE. We continually monitor both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change.

The partnership agreement requires that, within 45 days subsequent to the end of each quarter, the Partnership distributes 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, 2013, 2012 and 2011, the Partnership paid cash distributions to its unitholders of approximately $389.1 million, $251.7 million and $200.9 million, respectively, representing the four quarterly distributions in 2013, 2012 and 2011. See also Note 14 — Subsequent Events concerning distributions approved in January 2014 for the quarter ended December 31, 2013.

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.

Conversion of Subordinated Units. Upon payment of the cash distribution for the second quarter of 2013, the subordination period with respect to the Partnership’s 69,076,122 subordinated units expired and all outstanding subordinated units converted into common units on a one-for-one basis on August 15, 2013. The conversion did not impact the amount of the cash distribution paid or the total number of the Partnership’s outstanding units representing limited partner interests.

Class B Units. The Class B units are not entitled to cash distributions. Instead, prior to conversion into common units, the Class B units receive quarterly distributions of additional paid-in-kind Class B units. The amount of each quarterly distribution per Class B unit is the quotient of the quarterly distribution paid to the Partnership’s common units by the volume-weighted average price of the common units for the 30-day period prior to the declaration of the quarterly distribution to common units. Effective on the business day after the record date for the distribution on common units for the fiscal quarter ending December 31, 2014, each Class B unit will become convertible at the election of either the Partnership or the holders of such Class B unit into a common unit on a one-for-one basis. In the event of the Partnership’s liquidation, the holders of Class B units will be entitled to receive out of the Partnership’s assets available for distribution to the partners the positive balance in each such holder’s capital account in respect of such Class B units, determined after allocating the Partnership’s net income or net loss among the partners. All Class B units are held indirectly by affiliates of the Partnership’s general partner. The Class B units were issued at a discount to the market price of the common units which they are convertible. This discount totaling $58.3 million represents a beneficial conversion

feature and is reflected as an increase in common unitholders’ capital and a decrease in Class B units capital to reflect the fair value of the Class B units at issuance on the Partnership’s consolidated statement of changes in partners’ capital for the twelve months ended December 31, 2012. The beneficial conversion feature is considered a non-cash distribution recognized ratably from the issuance date of December 20, 2012, through the conversion date, resulting in an increase in Class B units capital and a decrease in common unitholders’ capital.

Class C Units. The Class C units were entitled to quarterly cash distributions after the common units received the minimum quarterly distribution, plus any arrearages from prior quarters. The Class C units participated pro rata thereafter and received the minimum quarterly distribution, after which the Class C units participated in further cash distributions pro rata with the Partnership’s common units. Effective on the business day after the record date for the distribution on common units for the fiscal quarter ending December 31, 2013, each Class C unit became convertible at the election of either the Partnership or the holders of such Class C unit into a common unit on a one-for-one basis. In the event of the Partnership’s liquidation, the holders of Class C units were entitled to receive out of the Partnership’s assets available for distribution to its partners the positive balance in each such holder’s capital account in respect of such Class C units, determined after allocating the Partnership’s net income or net loss among the Partners. All Class C units were held indirectly by affiliates of the Partnership’s general partner. The Class C units were issued at a discount to the market price of the common units which they are convertible. This discount totaling $36.7 million represents a beneficial conversion feature and is reflected as an increase in common unitholders’ capital and a decrease in Class C units capital to reflect the fair value of the Class C units at issuance on the Partnership’s consolidated statement of changes in partners’ capital for the twelve months ended December 31, 2012. The beneficial conversion feature is considered a non-cash distribution recognized ratably from the issuance date of December 20, 2012, through the conversion date, resulting in an increase in Class C units capital and a decrease in common unitholders’ capital. Effective February 19, 2014, all of the Class C units converted into common units on a one-for-one basis. Please read Note 14 (Subsequent Events).

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 Class B 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 unitholders (and Class B unitholders, upon conversion of Class B units to common units) 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:

The table above assumes that the Partnership’s general partner maintains its two percent general partner interest, that there are no arrearages on common units and the general partner continues to own the incentive distribution rights. 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.

The Partnership’s net income attributable to the Partnership’s assets for periods including and subsequent to the Partnership’s acquisitions of the Partnership’s assets is allocated to the general partner and the limited partners, including any subordinated, Class B and Class C 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, subordinated, Class B and Class C 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, Class B and Class C 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, 2013			December 31, 2012			December 31, 2011
Net income attributable to Access Midstream Partners, L.P.	$	336,025		$	178,455		$	194,337
Less general partner interest in net income		(40,681	)		(8,481	)		(5,070	)
Limited partner interest in net income	$	295,344		$	169,974		$	189,267
Net income allocable to common units⁽¹⁾		147,706			89,019			94,896
Net income allocable to subordinated units		52,564			78,736			94,371
Net income allocable to Class B units⁽¹⁾		45,987			1,038			—
Net income allocable to Class C units⁽¹⁾		49,087			1,181			—
Limited partner interest in net income	$	295,344		$	169,974		$	189,267
Net income per limited partner unit – basic and diluted
Common units	$	1.01		$	1.11		$	1.37
Subordinated units	$	0.93		$	1.14		$	1.37
Weighted average limited partner units outstanding – basic and diluted
Common units		132,708,675			80,058,682			69,371,194
Subordinated units		42,770,421			69,076,122			69,076,122
Total		175,479,096			149,134,804			138,447,316

In June 2012, Chesapeake sold all of its ownership interests in the Partnership and its general partner; however, Mr. Dell’Osso, Executive Vice President and Chief Financial Officer of Chesapeake, remained on the Partnership’s board of directors. The Partnership does not expect to complete additional significant transactions with Chesapeake. While Mr. Dell’Osso remains on the Partnership’s board, the Partnership no longer considers Chesapeake to be an affiliate of Access Midstream Partners. Because Chesapeake was the Partnership’s affiliate for a portion of 2012, set forth below is a description of the Partnership’s transactions with Chesapeake prior to 2013.

Affiliate transactions. In the normal course of business, natural gas gathering, treating and other midstream services were provided to Chesapeake and its affiliates. Revenues were derived primarily from Chesapeake, which included volumes attributable to third-party interest owners that participated in Chesapeake’s operated wells.

Omnibus Agreement. The Partnership entered into an omnibus agreement with Access Midstream Ventures and Chesapeake Midstream Holdings that addressed the Partnership’s right to indemnification for certain liabilities and its obligation to indemnify Access Midstream Ventures and affiliated parties for certain liabilities.

General and Administrative Services and Reimbursement. Pursuant to a services agreement, Chesapeake and its affiliates provided certain services including legal, accounting, treasury, human resources, information technology and administration. The employees supporting these operations were employees of Chesapeake Energy Marketing Inc. (“CEMI”) or Chesapeake. The consolidated financial statements for the Partnership and the predecessor included 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 indicated corporate overhead costs were 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 was calculated as the lesser of $0.0310/Mcf gathered or actual corporate overhead costs. General and administrative charges were $22.3 million and $23.7 million for the years ended December 31, 2012 and 2011 for the Partnership.

Additional Services and Reimbursement. At the Partnership’s request, Chesapeake also provided 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 were not already provided by the seconded employees. In return for such additional services, the general partner reimbursed 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 was not subject to the general and administrative services reimbursement cap.

Chesapeake 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 did 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 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. The cost for these support services was $0.4 million, $1.7 million, and $0.6 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Employee Secondment Agreement. Chesapeake, certain of its affiliates and the Partnership’s general partner entered into an amended and restated employee secondment agreement pursuant to which specified employees of Chesapeake were seconded to the general partner and provided 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, were seconded to the general partner pursuant to this agreement. The general partner, subject to specified exceptions and limitations, reimbursed Chesapeake on a monthly basis for substantially all costs and expenses Chesapeake incurred 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 $49.4 million and $42.1 million for the years ended December 31, 2012 and 2011, respectively. These charges included $37.7 million and $37.7 million in operating expenses and $11.7 million and $4.4 million in general and administrative expenses for the years end December 31, 2012 and 2011, respectively, in the accompanying consolidated statements of operations.

Shared Services Agreement. In return for the services of Mr. Stice as the chief executive officer of the Partnership’s general partner during the years ended December 2012 and 2011, its general partner entered into a shared services agreement with Chesapeake pursuant to which its general partner reimbursed certain of the costs and expenses incurred by Chesapeake in connection with Mr. Stice’s employment. The general partner was 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 was determined based on the amount of time Mr. Stice actually spent working for the Partnership.

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 provide 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 providing 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 provide compression equipment to the Partnership in the acreage dedications through September 30, 2016. Thereafter, the Partnership will have the right to continue receiving such equipment through September 30, 2019 at market rates to be agreed upon between the parties or to receive compression equipment from unaffiliated third parties. MidCon Compression guarantees to the Partnership that the compressors will meet specified run time and throughput performance guarantees. The monthly rates are reduced for any equipment that does not meet these guarantees. 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. The Partnership receives 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 charges from affiliates were $65.3 million and $57.6 million for the years ended December 31, 2012 and 2011, respectively. 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 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.

Chesapeake is the only customer from whom revenues exceeded 10 percent of consolidated revenues for the year ended December 31, 2013 for the Partnership. Chesapeake and Total are the only customers from whom revenues exceeded 10 percent of consolidated revenues for the years ended December 31, 2012 and 2011 for the Partnership. The percentage of revenues from Chesapeake, Total and other customers are as follows:

Financial instruments that potentially subject the Partnership to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. On December 31, 2013 and 2012, respectively, cash and cash equivalents were invested in a non-interest bearing account and money market funds with investment grade ratings. On December 31, 2013 and 2012, respectively, Chesapeake accounted for $176.5 million and $80.0 million of the Partnership’s accounts receivable balance.

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

Included in gathering systems is $620.5 million and $455.4 million at December 31, 2013 and 2012, respectively, that is not subject to depreciation as the systems were under construction and had not been put into service.

Depreciation expense, including capital lease amortization, was $271.7 million, $153.8 million and $124.7 million for the years ended December 31, 2013, 2012 and 2011, respectively, for the Partnership.

CMO. On December 20, 2012, the Partnership acquired from CMD 100 percent of the issued and outstanding equity interests in Chesapeake Midstream Operating, L.L.C. (“CMO”) for total consideration of $2.16 billion. Through the acquisition of CMO, the Partnership owns certain midstream assets in the Eagle Ford, Utica, Niobrara, Haynesville, Marcellus and Mid-Continent regions. These assets include, in aggregate, approximately 1,675 miles of pipeline and 4.3 million dedicated acres as of the date of the acquisition. See Note 1 to the consolidated financial statements for additional information.

The results of operations presented and discussed in this annual report include results of operations from the CMO acquisition for the twelve-day period from closing of the acquisition on December 20, 2012 through December 31, 2012. For this period, income attributable to CMO operations was $3.0 million. The purchase price in excess of the value underlying the gas gathering system assets and working capital is approximately $263.3 million and is attributable to customer relationships acquired. This intangible asset is being amortized over a 20 year period on a straight-line basis.

The table below reflects the final allocation of the purchase price to the assets acquired and the liabilities assumed in the CMO Acquisition (in thousands).

The initial purchase price allocation was based on an assessment of the fair value of the assets acquired and liabilities assumed in the CMO Acquisition. The fair values of the gathering assets, related equipment, and intangible assets acquired were based on the market, cost and income approaches. All fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. Upon completion of the initial purchase price allocation, the Partnership reviewed its assessment, including the identification and fair valuation of assets acquired and liabilities assumed. During the third quarter 2013, the Partnership finalized certain of the estimates used in the initial purchase price allocation, primarily with respect to the valuation of assets and liabilities assumed in the Marcellus region. The balance sheet has been prospectively adjusted to reflect these changes, the most significant of which included a decrease to property, plant and equipment of $70.8 million, an increase to intangible assets of $55.4 million and an increase to other net assets of $15.4 million. None of the adjustments impacted the partnership’s statements of operations.

Marcellus. On December 29, 2011, the Partnership acquired from CMD all of the issued and outstanding common units of Appalachia Midstream for total consideration 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, 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 549 miles of gas gathering pipeline in the Marcellus Shale.

The results of operations presented and discussed in this annual report include results of operations from the Appalachia Midstream for the full year of operations in 2012 and the three-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 the three-day period ended December 31, 2011, 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 is being amortized over a 15 year period on a straight-line basis.

The following table presents the pro forma condensed financial information of the Partnership as if the CMO Acquisition and our acquisition of Appalachia Midstream each occurred on January 1, 2011. 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 CMO and Appalachia Midstream to the Partnership.

On September 4, 2013, the Partnership sold Mid-Atlantic Gas Services, L.L.C. (“Mid-Atlantic”) to Chesapeake for net proceeds of $32.9 million. Mid-Atlantic was acquired by the Partnership in December 2012 as part of the CMO Acquisition and consisted of midstream assets in the Marcellus Shale region. These assets were not part of the Partnership’s equity investment in Appalachia Midstream. The net proceeds equaled the Partnership’s basis in the assets. Consequently, the Partnership did not recognize any gain or loss as a result of the sale.

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 operates 100 percent of and owns an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 549 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. The 10 gathering systems are separate investments with varying ownership percentages and each gathering system is accounted for as an equity investment because all capital expenditures and other operating decisions must be approved by a supermajority vote of the gathering system’s owners.

Utica East Ohio Midstream, LLC. The Partnership acquired UEOM as part of the CMO Acquisition in December 2012. In March 2012, CMO entered into an agreement to form Utica East Ohio Midstream LLC (“UEOM”) with M3 Midstream, L.L.C. and EV Energy Partners, L.P. to develop necessary infrastructure for the gathering, processing and fractionation of natural gas and NGLs in the Utica Shale play in Eastern Ohio. The infrastructure complex, which is currently under construction, consists of natural gas gathering and compression facilities constructed and operated by the Partnership, as well as processing, NGL fractionation, loading and terminal facilities constructed and operated by M3 Midstream, L.L.C. The Partnership owns a 49 percent interest and UEOM is accounted for as an equity investment because the power to direct the activities which are most significant to UEOM’s economic performance is shared between the Partnership and the other equity holders.

Ranch Westex JV, LLC. The Partnership acquired Ranch Westex as part of the CMO Acquisition in December 2012. On December 1, 2011, CMO entered into a joint venture to form Ranch Westex JV, LLC. (“Ranch Westex”) with Regency Energy Partners, LP and Anadarko Pecos Midstream LLC to build a processing facility in Ward County, Texas, to process natural gas delivered from the liquids-rich Bone Springs and Avalon Shale formations. The Partnership owns a 33.33 percent interest and Ranch Westex is accounted for as an equity method investment because the power to direct the activities that are most significant to Ranch Westex’s economic performance is shared among the three equity holders. The project consists of two plants, a refrigeration plant and a cryogenic processing plant.

The following tables sets forth summarized financial information of the investments in which the Partnership acquired an interest in December 2013 and 2012, as follows:

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.

The following table presents the Partnership’s outstanding debt as of December 31, 2013 and 2012 (in thousands):

Revolving Credit Facility. On May 13, 2013, the Partnership amended its existing senior secured revolving credit facility. The amended and restated revolving credit facility matures in May 2018 and includes revolving commitments of $1.75 billion, including a sub-limit of $100 million for same-day swing line advances and a sublimit of $200 million for letters of credit. In addition, the revolving credit facility’s accordion feature allows the Partnership to increase the available borrowing capacity under the facility up to $2.0 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 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 0.50 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 1.50 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 0.375 percent per annum while the Partnership is subject to the leverage-based pricing grid, according to the Partnership’s leverage ratio and (b) 0.15 percent to 0.30 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 or 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 and allows for the Partnership to release all collateral securing the revolving credit facility if the Partnership reaches investment grade status. The revolving credit facility agreement also requires the Partnership to maintain a consolidated leverage ratio of 5.5 to 1.0 (or 5.0 to 1.0 after the Partnership has released all collateral upon achieving investment grade status). The Partnership was in compliance with all covenants under the agreement at December 31, 2013.

Senior Notes. On December 19, 2012, the Partnership and ACMP Finance Corp., a wholly owned subsidiary of Access MLP Operating, L.L.C., completed a public offering of $1.4 billion in aggregate principal amount of 4.875 percent senior notes due 2023 (the “2023 Notes”). The Partnership used a portion of the net proceeds to fund a portion of the purchase price for the CMO Acquisition, and the balance to repay borrowings outstanding under the Partnership’s revolving credit facility. Debt issuance costs of $25.9 million are being amortized over the life of the 2023 Notes.

On January 11, 2012, the Partnership and ACMP Finance Corp. completed a private placement of $750.0 million in aggregate principal amount of 6.125 percent senior notes due 2022 (the “2022 Notes”). 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. Debt issuance costs of $13.8 million are being amortized over the life of the 2022 Notes.

On April 19, 2011, the Partnership and ACMP 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”). 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 $8.2 million are being amortized over the life of the 2021 Notes.

On August 14, 2013, the Partnership issued $400 million in aggregate principal amount of additional 5.875 percent senior notes due 2021 (the “Additional Notes”). The Additional Notes are additional to the $350 million of 2021 Notes initially issued on April 19, 2011 and are fully fungible with, rank equally with and form a single series with the 2021 Notes. The Additional Notes were issued at a price of 101.5 percent of the principal amount plus accrued interest from April 15, 2013, resulting in net proceeds of $400.8 million, which was used for general partnership purposes, including funding working capital, repayment of indebtedness and funding the Partnership’s capital expenditure program. Debt issuance costs of $5.8 million are being amortized over the life of the Additional Notes.

The 2023 Notes will mature on May 15, 2023, and interest is payable on May 15 and November 15 of each year. The Partnership has the option to redeem all or a portion of the 2023 Notes at any time on or after December 15, 2017, at the redemption price specified in the indenture relating to the 2023 Notes, plus accrued and unpaid interest. The Partnership may also redeem the 2023 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 December 15, 2017. In addition, the Partnership may redeem up to 35 percent of the 2023 Notes prior to December 15, 2015 under certain circumstances with the net cash proceeds from certain equity offerings.

The 2022 Notes will mature on July 15, 2022 and interest is payable on January 15 and July 15 of each year. The Partnership has 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. The Partnership 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, the Partnership 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.

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 2023 Notes, 2022 Notes and the 2021 Notes indentures contain covenants that, among other things, limit the Partnership’s ability and the ability of certain of the Partnership’s subsidiaries to: (1) sell assets including equity interests in its subsidiaries; (2) pay distributions on, redeem or purchase the Partnership’s units, or redeem or purchase the Partnership’s 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 the Partnership’s or certain of the Partnership’s subsidiaries’ assets; (8) engage in transactions with affiliates; and (9) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the 2023 Notes, 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 indentures, has occurred or is continuing, many of these covenants will terminate.

The Partnership, as the parent company, has no independent assets or operations. The Partnership’s operations are conducted by its subsidiaries through its primary operating company subsidiary, Access MLP Operating, L.L.C., a direct 100 percent owned subsidiary of the Partnership. Access MLP Operating, L.L.C. and each of the Partnership’s other direct and indirect 100 percent owned subsidiaries is a guarantor, other than ACMP Finance Corp., an indirect 100 percent owned subsidiary of the Partnership whose sole purpose is to act as co-issuer of any debt securities. The guarantees 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 applicable 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.

Capitalized Interest. Interest expense was net of capitalized interest of $43.9 million, $14.6 million, and $9.5 million for the years ended December 31, 2013, 2012 and 2011, respectively, for the Partnership.

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, 2013 or 2012.

Operating 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 $104.5 million, $81.1 million, $60.7 million for the years ended December 31, 2013, 2012 and 2011, respectively, for the Partnership. The Partnership’s remaining contractual lease obligations as of December 31, 2013 include 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. Contractual lease obligations also include remaining payments for the Partnership’s headquarter buildings and other lease agreements.

Future minimum rental payments due under operating leases as of December 31, 2013 are as follows:

Capital lease commitments. The Partnership entered into one and three year capital leases for certain computer equipment.

The following are the minimum lease payments to be made in each of the following years indicated for the capital lease in effect as of December 31, 2013 (in thousands):

Prior to the CMO Acquisition, the Partnership’s operations were organized into a single business segment. As a result of the CMO Acquisition, the Partnership added assets in three new operating regions. Effective January 1, 2013, the Partnership’s chief operating decision maker began to measure performance and allocate resources based on geographic segments. The Partnership’s operations are divided into eight operating segments: Barnett Shale, Eagle Ford Shale, Haynesville Shale, Marcellus Shale, Niobrara Shale, Utica Shale, Mid-Continent and Corporate. Summarized financial information for the reportable segments is shown in the following tables, presented in thousands.

For the year ended December 31, 2013
	Barnett			Eagle Ford			Haynesville			Marcellus			Niobrara
Revenues	$	433,709		$	278,282		$	119,209		$	10,989		$	15,095
Operating expenses		96,926			59,059			41,176			4,834			9,090
Depreciation and amortization expense		97,941			51,433			80,770			1,381			4,284
General and administrative expense		—			—			—			—			—
Other operating expense		—			—			—			—			—
Operating income (loss)	$	238,842		$	167,790		$	(2,737	)	$	4,774		$	1,721
Income (loss) from unconsolidated affiliates	$	—		$	—		$	—		$	133,036		$	—
Capital expenditures	$	50,627		$	316,002		$	17,186		$	2,590	⁽¹⁾	$	59,115	⁽²⁾
Total assets	$	1,511,405		$	1,172,022		$	1,276,795		$	1,452,797		$	137,319
	Utica			Mid-Continent			Corporate			Consolidated
Revenues	$	44,063		$	171,875		$	—		$	1,073,222
Operating expenses		19,065			70,609			37,957			338,716
Depreciation and amortization expense		9,451			36,435			14,484			296,179
General and administrative expense		—			—			104,332			104,332
Other operating expense		—			—			2,092			2,092
Operating income (loss)	$	15,547		$	64,831		$	(158,865	)	$	331,903
Income (loss) from unconsolidated affiliates	$	(3,842	)	$	1,226		$	—		$	130,420
Capital expenditures	$	342,839	⁽³⁾	$	106,718	⁽⁴⁾	$	163,522		$	1,058,599
Total assets	$	1,040,199		$	773,104		$	553,805		$	7,917,446

For the year ended December 31, 2012
	Barnett			Eagle Ford			Haynesville			Marcellus			Niobrara
Revenues	$	395,467		$	7,232		$	68,184		$	783		$	116
Operating expenses		101,703			1,604			15,642			188			85
Depreciation and amortization expense		93,343			968			33,210			6			79
General and administrative expense		—			—			—			—			—
Other operating expense		—			—			—			—			—
Operating income (loss)	$	200,421		$	4,660		$	19,332		$	589		$	(48	)
Income (loss) from unconsolidated affiliates	$	—		$	—		$	—		$	67,592		$	—
Capital expenditures	$	98,507		$	11,796		$	23,578		$	—	⁽¹⁾	$	1,967
Total assets	$	1,573,789		$	925,694		$	1,324,599		$	1,142,550		$	91,236
	Utica			Mid-Continent			Corporate			Consolidated
Revenues	$	353		$	136,312		$	—		$	608,447
Operating expenses		159			52,979			25,279			197,639
Depreciation and amortization expense		48			32,042			5,821			165,517
General and administrative expense		—			—			67,579			67,579
Other operating expense		—			—			(766	)		(766	)
Operating income (loss)	$	146		$	51,291		$	(97,913	)	$	178,478
Income (loss) from unconsolidated affiliates	$	(38	)	$	(12	)	$	—		$	67,542
Capital expenditures	$	126		$	184,285		$	30,241		$	350,500
Total assets	$	356,662		$	714,510		$	432,060		$	6,561,100

For the year ended December 31, 2011
	Barnett		Eagle Ford		Haynesville			Marcellus		Niobrara
Revenues	$	361,843	$	—	$	93,107		$	—		—
Operating expenses		94,009		—		18,057			—		—
Depreciation and amortization expense		76,979		—		29,051			—		—
General and administrative expense		—		—		—			—		—
Other operating expense		—		—		—			—		—
Operating income	$	190,855	$	—	$	45,999		$	—	$	—
Income from unconsolidated affiliates	$	—	$	—	$	—		$	433	$	—
Capital expenditures	$	253,126	$	—	$	56,087		$	—	$	—
Total Assets	$	1,584,207	$	—	$	527,527		$	886,558	$	—
	Utica		Mid-Continent		Corporate			Consolidated
Revenues	$	—	$	110,979	$	—		$	565,929
Operating expenses		—		47,749		17,036			176,851
Depreciation and amortization expense		—		28,014		2,125			136,169
General and administrative expense		—		—		40,380			40,380
Other operating expense		—		—		739			739
Operating income	$	—	$	35,216	$	(60,280	)	$	211,790
Income from unconsolidated affiliates	$	—	$	—	$	—		$	433
Capital expenditures	$	—	$	88,259	$	21,362		$	418,834
Total Assets	$	—	$	531,410	$	153,536		$	3,683,238

On January 24, 2014, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.555 per unit, or $122.1 million in aggregate. The cash distribution was paid on February 14, 2014 to unitholders of record at the close of business on February 7, 2014.

Under the partnership agreement, the Class C units became convertible into common units on a one-for-one basis at the election of either the Partnership or the holders of the Class C units on February 10, 2014 (the first business day following the record date for the Partnership’s 2013 fourth quarter cash distribution). After February 10, 2014, the Partnership received notice from certain of the GIP II Entities and Williams, as holders of the Class C units, of their election to convert all of the Class C units. All of the outstanding Class C units were converted into common units on a one-for-one basis effective February 19, 2014. The common units resulting from this conversion will participate pro rata with the other common units in quarterly distributions. The conversion did not impact the total number of the Partnership’s outstanding units representing limited partner interests.

Summarized unaudited quarterly financial data for 2013 and 2012 are as follows ($ in thousands except per share data):

	Quarters Ended
	March 31, 2013		June 30, 2013		September 30, 2013		December 31, 2013
Total revenues	$	236,959	$	247,242	$	260,943	$	328,078
Gross profit^(a)	$	154,196	$	164,398	$	177,410	$	238,502
Net income	$	60,696	$	70,427	$	79,211	$	130,815
Net income attributable to Access Midstream Partners, L.P.	$	59,538	$	69,213	$	78,217	$	129,057
Net income per common units	$	0.14	$	0.18	$	0.22	$	0.47
Net income per subordinated units	$	0.29	$	0.31	$	0.33	$	—
	Quarters Ended
	March 31, 2012		June 30, 2012		September 30, 2012		December 31, 2012
Total revenues	$	154,674	$	149,332	$	156,092	$	148,349
Gross profit^(a)	$	105,992	$	104,601	$	106,287	$	93,928
Net income	$	52,366	$	51,606	$	50,228	$	24,187
Net income attributable to Access Midstream Partners, L.P.	$	52,366	$	51,606	$	50,228	$	24,255
Net income per common units	$	0.34	$	0.34	$	0.32	$	0.11
Net income per subordinated units	$	0.34	$	0.34	$	0.32	$	0.14

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, 2013.

No changes in the Partnership’s internal control over financial reporting occurred during the quarter ended December 31, 2013, that have materially affected, or are reasonably likely to materially affect, the Partnership’s 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.

As a limited partnership, we have no directors or officers. Instead, Access Midstream Partners 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. Access Midstream Ventures, which is jointly and equally owned by the GIP II Entities and Williams, 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, and the GIP II Entities and Williams have agreed between themselves as to how and when replacement, removals and appointments of directors may be made. Our general partner currently has 13 directors: Alan S. Armstrong, Donald R. Chappel, James E. Scheel, James J. Cleary, William A. Woodburn, William J. Brilliant, J. Mike Stice, Robert S. Purgason, Dominic J. Dell’Osso, Jr., David A. Daberko, Philip L. Frederickson, Suedeen G. Kelly and William B. Berry. Our general partner’s board of directors has affirmatively determined that David A. Daberko, William B. Berry, Philip L. Frederickson 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, a compensation committee and a risk committee.

The officers of our general partner manage and conduct our operations. In 2013, all of the executive officers of our general partner devoted all of their time to manage and conduct our operations.

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.

J. Mike Stice, Ed.D. has served as Chief Executive Officer of our general partner since January 2010 and as a director of our general partner since July 2012. Mr. Stice was also Senior Vice President—Natural Gas Projects of Chesapeake Energy Corporation and President and Chief Operating Officer of Chesapeake’s primary midstream subsidiaries from November 2008 through December 2012. Prior to joining our general partner and 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, as President of Gas and Power and as President of Energy Solutions in addition to other roles in ConocoPhillips’ upstream and 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. Mr. Stice also serves on the board of directors of U.S. Silica Holdings, Inc. (NYSE: SLCA). We believe that Mr. Stice’s extensive formal education and proven leadership skills bring important experience and skill to the board.

Robert S. Purgason has served as Chief Operating Officer of our general partner since January 2010 and as a director of our general partner since July 2012. 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. We believe that Mr. Purgason’s long experience with the formation and management of several MLPs brings important experience and skill to the board.

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.

Walter Bennett has served as Senior Vice President – Western Operations of our general partner since December 2013 and manages the Anadarko, Midcontinent, Niobrara, Barnett, Permian, Eagle Ford and Haynesville operating areas. He most recently was Vice President – Western Operations for Access. Prior, he was Chief Operating Officer of Chesapeake Midstream Development. Prior to joining our general partner, Mr. Bennett served as Senior Vice President-Operations at Boardwalk Pipeline Partners in Houston, Texas. Previously, Mr. Bennett served in a variety of senior positions at Gulf South Pipeline Company that included operations and commercial responsibilities. He began his career at a subsidiary of Koch Industries in Gary, Indiana. Mr. Bennett earned his Bachelor of Science degree in Mechanical Engineering from the University of Wisconsin-Madison in 1992 and his Master of Business Administration from Louisiana State University in 2004.

John D. Seldenrust has served as Senior Vice President – Eastern Operations of our general partner since December 2013 and manages both the Marcellus and Utica operating areas, including overseeing the Utica East Ohio and other existing joint venture relationships in the area. He most recently served as Vice President – Eastern Operations and was formerly Vice President - Engineering & Construction for our general partner, a role he held since 2008. In this position, Mr. Seldenrust helped lead Access’ infrastructure expansion, including conceptual design, procurement, construction, engineering standards and operations support. Prior to joining our general partner, Mr. Seldenrust held Reservoir, Production and Facilities Engineering positions with ARCO Oil & Gas, Vastar Resources and BP America. He earned a degree in Chemical Engineering from Texas A&M University in 1987.

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), Marathon Petroleum Corporation (NYSE: MPC) and MPLX LP (NYSE: MPLX). He is a trustee of Case Western Reserve University, University Hospitals Health System and Hawken School. Mr. Daberko also previously served 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.

Alan S. Armstrong has served as a director of our general partner since December 2012. Mr. Armstrong currently serves as president and chief executive officer of Williams (NYSE: WMB), which owns approximately 22.6% of our limited partner interests and 50% of our general partner. Prior to that, Mr. Armstrong served as president of Williams’ midstream and olefins business in Canada and the United States. Additionally, he serves as chairman of the board and chief executive officer for Williams Partners L.P. (NYSE: WPZ) and serves as a director of BOK Financial Corporation (NASDAQ: BOKF). Previously, Mr. Armstrong served Williams as vice president of Gathering & Processing; vice president of Commercial Development; vice president of Retail Energy Services and director of Commercial Operations for Williams Field Services’ Gulf Coast division. He joined Williams in 1986 as an engineer. Mr. Armstrong graduated from the University of Oklahoma in 1985 with a bachelor’s degree in civil engineering. We believe that Mr. Armstrong’s experience in the energy industry, particularly his midstream expertise, brings important experience and skill to the board.

William B. Berry has served as a director of our general partner since June 2013. Mr. Berry is a retired oil and gas executive with over 37 years of industry experience. From 2003 to 2008, he was Executive Vice President of ConocoPhillips. He also held other senior executive positions with Phillips Petroleum Co., including Senior Vice President, Exploration and Production. Prior to his executive positions, he held various management roles including Manager, Corporate Planning and Budgeting. Mr. Berry also serves on the boards of directors for Willbros Group Inc. (NYSE: WG) and Teekay Corp (NYSE: TK). He has bachelor’s and master’s degrees in petroleum engineering from Mississippi State University, where he also serves on the Dean’s Advisory Council and the Foundation Board. In March 2010, he became the Honorary Consul for the Consulate of the Republic of Kazakhstan in Houston. We believe that Mr. Berry’s energy industry background brings important experience and skill to the board.

William J. Brilliant has served as a director of our general partner since June 2012. Mr. Brilliant is currently a Principal of GIP, which owns approximately 31.2% of our limited partner interests and 50% of our general partner, and focuses on North American energy investments, where he has served as a member of the investment team since May 2007. Prior to joining GIP, Mr. Brilliant was an investment banker in the Global Financial Sponsors Group at Lehman Brothers from 2005 to 2007, providing M&A and financial advisory to investment funds throughout their investment cycle. Mr. Brilliant graduated from the University of California at Los Angeles in 1998 and the Wharton School at the University of Pennsylvania in 2005. We believe that Mr. Brilliant’s energy industry background, particularly his expertise in mergers and acquisitions, brings important experience and skill to the board.

Donald R. Chappel has served as a director of our general partner since December 2012. Mr. Chappel currently serves as senior vice president and chief financial officer for Williams (NYSE: WMB), which owns approximately 22.6% of our limited partner interests and 50% of our general partner. He was a key member of the executive team that led Williams’ successful turnaround, and led the restructuring of the company’s finances, including strengthened capital discipline, business process/IT reengineering and outsourcing. Mr. Chappel also led several key strategic initiatives including Williams’ IPO of Williams Partners (NYSE:WPZ), the drop-down of key assets, the merger of Williams Partners and Williams Pipeline Partners LP, the planned separation of Williams’ E&P business and Williams’ repositioning as an energy infrastructure company with a high dividend/high growth financial strategy. Mr. Chappel joined the board of directors of SuperValu (NYSE: SVU) in 2010 and serves on its audit committee, corporate governance and nominating committee. Mr. Chappel’s previous experience includes several key positions at Waste Management, where he twice held the position of chief financial officer. Mr. Chappel also served in financial leadership roles at Beatrice Companies, Esmark and Arthur Andersen & Company. Mr. Chappel graduated from the University of Illinois with a bachelor’s degree in accounting and is a certified public accountant. We believe that Mr. Chappel’s experience in the energy industry, particularly his financial strategy and oversight expertise, brings important experience and skill to the board.

James J. Cleary has served as a director of our general partner since December 2013. Mr. Cleary joined GIP, which owns approximately 31.2% of our limited partner interests and 50% of our general partner, in May 2012 and currently serves as a managing director. Prior to joining GIP, Mr. Cleary was the President of El Paso Corporation’s Western Pipelines and previously served as the President of ANR Pipeline Company. Prior to 2001, Mr. Cleary was the Executive Vice President and General Counsel of Southern Natural Gas Company. He has served on the board of Gibson Energy Inc. (TSX: GEI) since April 2013. Mr. Cleary graduated from the College of William & Mary in 1976 and from Boston College Law School in 1979. We believe that Mr. Cleary’s extensive energy industry background, particularly his natural gas pipeline expertise, 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; General Manager, Refining and Marketing Europe; Managing Director, Conoco Ireland; General Manager, Refining and Marketing; 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) and as a director emeritus for the Yellowstone Park Foundation. 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.

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 of Akin Gump Strauss Hauer & Feld LLP since November 2012. From April 2010 to October 2012, Ms. Kelly was a Partner in the law firm of Patton Boggs LLP. Ms. Kelly 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, Ms. Kelly 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, Ms. Kelly 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.

James E. Scheel has served as a director of our general partner since December 2012. Mr. Scheel currently serves as senior vice president of Northeast G&P for Williams Partners L.P. (NYSE: WPZ) and for Williams (NYSE: WMB). Before being appointed to his current role, Mr. Scheel previously served as senior vice president of corporate strategic development for Williams which owns approximately 22.6% of our limited partner interests and 50% of our general partner, where he was responsible for enterprise-level business development and customer relationship management. Mr. Scheel served as vice president of business development for Williams’ midstream business. Mr. Scheel joined Williams in 1988 as a business development analyst. Throughout his career at Williams, he has served in many leadership roles in the areas of business and strategic development, domestic and international operations, engineering and natural gas liquids marketing and has facilitated more than $6 billion in transactions and business integrations. Mr. Scheel graduated from the University of Tulsa in 1986 with a bachelor’s degree in petroleum engineering. We believe that Mr. Scheel’s extensive energy industry background, particularly his midstream expertise, brings 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, which owns approximately 31.2% of our limited partner interests and 50% of our general partner, 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 Gatwick Airport Limited, Terra-Gen Power Holdings, LLC and Edinburgh Airport. 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.

Our general partner’s board of directors has four standing committees: the audit committee, conflicts committee, compensation committee and risk 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 eight meetings in 2013.

Mr. Daberko has been designated by our general partner’s board of directors as an “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 above.

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 historically, GIP, Williams and/or Access 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 Williams, GIP and/or Access 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 two meetings in 2013.

Compensation Committee. The compensation committee consists of five members of our general partner’s board of directors, Messrs. Armstrong, Chappel, Daberko, Frederickson and Woodburn. Ms. Kelly was replaced as the chairman by Matthew C. Harris effective March 14, 2013. Mr. Harris was replaced as the chariman by Mr. Woodburn effective October 24, 2013. Mr. Woodburn 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 our Long Term Incentive Plan with respect to the officers of 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 five meetings in 2013.

Risk Committee. The risk committee consists of three members of our general partner’s board of directors, Messrs. Brilliant and Scheel and Ms. Kelly. Ms. Kelly is the current chairman of the risk committee. The objectives of the risk committee is to properly align, oversee and approve the Partnership’s management of key risks, including operational, reporting and compliance risks, as well as the guidelines, policies and processes for monitoring and mitigating such risks. The risk committee has adopted a charter, which has been ratified and approved by the board of directors. The risk committee held four meetings in 2013.

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:

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

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. Members of our general partner’s board of directors are designated or elected by the sole member of our general partner, Access 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, our general partner’s Vice President of Environmental Health and Safety and our general partner’s Vice President and General Counsel. Significant risks and the possible approaches to mitigate such risks are reviewed by the risk 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.

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 Amanda B. Warrington, Assistant Corporate Secretary, Access Midstream Partners, L.P., 525 Central Park Drive, Oklahoma City, Oklahoma 73105, or to fax number (405) 849-2504.

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.

James J. Cleary was appointed to our general partner’s board on December 23, 2013. The Form 3 required to be filed upon Mr. Cleary’s becoming a director was filed on January 3, 2014, which is one day after the due date, due to a clerical error. Additionally, Williams has not filed a Form 4 in connection with the conversion of its subordinated units into common units. 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 (other than Mr. Cleary) and greater than 10 percent unitholders (other than Williams) under Section 16(a) were satisfied during the year ended December 31, 2013.

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.accessmidstream.com, and in print to any unitholder who so requests, the Code of Ethics and our Corporate Governance Guidelines, audit committee charter, conflicts committee charter, compensation committee charter and the risk committee charter. Requests for print copies may be directed to Dave Shiels at dave.shiels@accessmidstream.com or to Investor Relations, Access Midstream Partners, L.P., 525 Central Park Drive, Oklahoma City, Oklahoma 73105, or by telephone at (877) 413-1023. 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.

This Compensation Discussion and Analysis describes the compensation system for our named executive officers for 2013 consisting of the following individuals: (1) J. Mike Stice, Chief Executive Officer; (2) Robert S. Purgason, Chief Operating Officer, (3) David C. Shiels, Chief Financial Officer, (4) Walter Bennett, Senior Vice President – Western Operations; and (5) John D. Seldenrust, Senior Vice President – Eastern Operations.

Our general partner manages our operations and activities, and through its board of directors and officers, makes decisions on our behalf. Prior to January 1, 2013, Chesapeake directly employed all of the persons responsible for managing our business, including the named executive officers, and our general partner reimbursed Chesapeake for the compensation paid by Chesapeake to such employees.

On January 1, 2013, the officers of our general partner and many of the Chesapeake employees that had previously been operating and providing services to our business, including the named executive officers, became employees of our general partner.

Effective as of January 1, 2013, our general partner entered into an employment agreement with each of our named executive officers. The employment agreements are the primary basis for the 2013 compensation mix and levels for each of the named executive officers and reflect our comprehensive approach to executive compensation. In 2013, our general partner reviewed each named executive officer’s performance twice. These reviews consisted of a subjective assessment of the overall performance of the named executive officer and his role and relative contribution. In our assessment of the performance of each named executive officer, we considered the following:

As part of this review, Mr. Stice provides recommendations to the compensation committee of the board of directors of our general partner with respect to the compensation levels of Messrs. Shiels, Purgason, Bennett and Seldenrust based on their respective employment agreements as well as a comprehensive, subjective evaluation of the Partnership’s performance and their individual performances. 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 Long-Term Incentive Plan (“LTIP”) and Management Incentive Compensation Plan (“MICP”) are also expressly approved by the board of directors of our general partner.

We provided short-term compensation in the form of base salaries, cash bonuses, long-term compensation in the form of equity awards and 401(k) matching contributions and certain perquisites.

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. Messrs. Shiels’, Bennett’s and Seldenrust’s base salaries increased $15,000, $35,000 and $16,000, respectively, during 2013. Messrs. Stice’s and Purgason’s base salaries did not increase in 2013. Cash bonuses paid during 2013 were intended to provide incentives based on a subjective performance assessment over a shorter period of time than the equity compensation listed below. Our named executive officers’ cash bonuses were determined by the compensation committee of the board of directors of our general partner in its discretion, based on its subjective assessment of our performance and our named executive officers’ performance over the first half of calendar year 2013 and over the second half of calendar year 2013. Mr. Bennett was paid $75,000 of his 2013 annual bonus on January 18, 2013, and $85,000 of his 2013 annual bonus on July 19, 2013.

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 Access’s semi-annual review of employee compensation. Mr. Bennett received an equity unit award valued at $105,000 on January 2, 2013, and an equity unit award valued at $300,000 on July 10, 2013. Each of Messrs. Stice, Purgason, Shiels, Bennett and Seldenrust received phantom unit awards under our LTIP, which is described below under “Long-Term Incentive Plan”.

Our general partner maintains the amended and restated MICP, providing incentive compensation awards consisting of two components, to key members of management who have been designated as participants by our general partner. Mr. Stice was granted an MICP award in December 2012 and Messrs. Shiels and Purgason were each granted MICP awards in December 2012 and January 2010. No MICP awards were granted to our named executive officers in 2013.

The first component of each award is an annual cash bonus based on “excess” cash distributions made by us above a specified target amount with respect to each fiscal quarter during which the award is outstanding, beginning with the fiscal quarter in which the grant date occurs (the “Excess Return Component”). A participant’s Excess Return Component will generally be calculated by multiplying the “excess” distribution amount for an applicable quarter (the amount of distributions that were made over “target” for that quarter) by the participant’s participation percentage assigned to him at the time of grant, by the annual payment percentage that is set forth in the MICP (unless otherwise assigned to the participant at the time of the grant). The Excess Return Component determined to be payable to a participant with respect to the quarters within a specified fiscal year (if any) is paid in annual installments over the first five years following the award commencement date, 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 a specified five-year period beginning on the award commencement date and is measured and paid at the end of such period (the “Equity Uplift Component”), unless a change of control occurs prior to the expiration of the period, at which time the award would be paid upon that change of control, as described in more detail below under “Potential Payments Upon Termination or 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 a date specified at the time of grant ($25.07 for the 2012 awards and $21.00 for the 2010 awards), 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.

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.

Access also provided compensation in the form of personal benefits and perquisites to the named executive officers in 2013. Most of the benefits that Access provided to the named executive officers are the same benefits that are provided to all employees or large groups of senior-level employees of Access, including health and welfare insurance benefits, 401(k) benefits, which include matching contributions (up to 12 percent of an employee’s annual base salary and cash incentive bonus compensation). Access does not have a pension plan or any other retirement plan other than the 401(k) and retirement restoration plans.

Each of the named executive officers is a party to an employment agreement with our general partner that became effective January 1, 2013, that governs 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.” The employment agreements are each described below.

Mr. Stice’s employment agreement became effective January 1, 2013 and has an initial employment term ending on June 30, 2017, subject to automatic one-year renewals thereafter. Pursuant to the agreement, Mr. Stice will serve as the Chief Executive Officer of our general partner, with an initial annual base salary of $750,000, subject to review and

increase by our general partner’s Board in its discretion. During the term of his employment, Mr. Stice is also eligible to participate in the employee benefit plans and arrangements, such as retirement, health and welfare plans and vacation programs that are customarily provided to similarly situated executives of our general partner, in accordance with the terms and conditions of such plans and arrangements. In addition, during his term of employment, our general partner may, in its discretion, pay annual or periodic bonus compensation to Mr. Stice from time to time, subject to the requirement that Mr. Stice be employed by our general partner on the bonus payment date. Mr. Stice also participates in the MICP and the LTIP.

Mr. Stice’s employment agreement provides for certain severance payments and benefits upon specified terminations of employment, as described in more detail below under “Potential Payments Upon Termination or Change in Control – Mike J. Stice Employment Agreement”. In addition, Mr. Stice may be entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our Severance Program, which is described in more detail below under “Potential Payments Upon Termination or Change in Control – Severance Program.”

The employment agreements for each of Messrs. Purgason and Shiels became effective on January 1, 2013 and have initial employment terms ending on November 30, 2014 and January 3, 2015, respectively, subject to automatic one-year renewals thereafter. Pursuant to their respective agreements, Mr. Purgason will serve as the Chief Operating Officer of our general partner, with an initial annual base salary of $450,000, subject to review and increase by our general partner’s Board in its discretion, and Mr. Shiels will serve as the Chief Financial Officer of our general partner, with an initial annual base salary of $400,000, subject to review and increase by our general partner’s Board in its discretion. During the term of their employment with our general partner, Messrs. Purgason and Shiels are eligible to participate in the employee benefit plans and arrangements, such as retirement, health and welfare plans and vacation programs that are customarily provided to similarly situated employees of our general partner, in accordance with the terms and conditions of such plans and arrangements. In addition, during their employment terms, discretionary bonuses may be paid to Messrs. Purgason and Shiels as determined by our general partner. Messrs. Purgason and Shiels also participate in the MICP and the LTIP.

The employment agreements for Messrs. Purgason and Shiels each provide for certain severance payments and benefits upon specified terminations of employment, as described in more detail below under “Potential Payments Upon Termination or Change in Control – David C. Shiels and Robert S. Purgason Employment Agreement”. In addition, Messrs. Purgason and Shiels may be entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our Severance Program, which is described in more detail below under “Potential Payments Upon Termination or Change in Control – Severance Program.”

The employment agreements for each of Messrs. Bennett and Seldenrust became effective on January 1, 2013 and have initial employment terms ending on December 31, 2017. Pursuant to their respective agreements, Mr. Bennett will serve as the Senior Vice President of Western Operations of our general partner, with an initial annual base salary of $300,000, subject to review and increase by our general partner’s Board in its discretion, and Mr. Seldenrust will serve as the Senior Vice President of Eastern Operations of our general partner, with an initial annual base salary of $370,000, subject to review and increase by our general partner’s Board in its discretion. During the term of their employment with our general partner, Messrs. Bennett and Seldenrust are eligible to participate in the employee benefit plans and arrangements, such as retirement, health and welfare plans and vacation programs that are customarily provided to similarly situated employees of our general partner, in accordance with the terms and conditions of such plans and arrangements.

Mr. Bennett’s employment agreement provides that he is eligible to receive a target annual bonus equal to $125,000 with respect to calendar year 2013. In addition, Mr. Bennett is eligible to receive target annual bonuses equal to $150,000 and $175,000 with respect to calendar years 2014 and 2015, respectively. Additionally, discretionary bonuses may be paid to Mr. Bennett as determined by our general partner. Mr. Seldenrust’s employment agreement provides that discretionary bonuses may be paid to him as determined by our general partner.

Messrs. Bennett and Seldenrust also participate in the LTIP. With respect to the 2013 calendar year, Mr. Bennett was eligible to receive an equity unit award under the LTIP with a targeted value of $125,000. In addition, with respect to the 2014 and 2015 calendar years, Mr. Bennett is eligible to receive an equity unit award under the LTIP with a targeted value of $150,000 and $175,000, respectively.

The employment agreements for Messrs. Bennett and Seldenrust each provide for certain severance payments and benefits upon specified terminations of employment, as described in more detail below under “Potential Payments Upon Termination or Change in Control – Walter Bennett and John D. Seldenrust Employment Agreement”. In addition, Messrs. Bennett and Seldenrust may be entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our Severance Program, which is described in more detail below under “Potential Payments Upon Termination or Change in Control – Severance Program.”

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 Access Midstream Partners 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, 2013.

Our general partner has adopted the Access Midstream LTIP, for employees, consultants and directors of our general partner and its affiliates, 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.

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 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.

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.

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 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.

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:

The following table summarizes the compensation amounts for each of the named executive officers for the fiscal years ended December 31, 2013, 2012 and 2011.

Name and Principal Position	Year	Salary ($)(1)		Bonus ($)(2)		Stock Awards ($)(3)		Option Awards ($)(3)		Non-Equity Incentive Plan Compen- sation ($) (4)		Change in Pension Value and Nonqualified Deferred Compen- sation Earnings ($)		All Other Compen- sation ($)(6)		Total ($)
J. Mike Stice⁽⁵⁾	2013		747,115		826,150		3,262,875		—		324,721		—		67,802		5,228,663
Chief Executive Officer	2012		342,308		1,562,875		881,062		—		29,848		—		299,403		3,115,496
Chief Executive Officer	2011		299,038		263,000		931,867		—		—		—		154,284		1,648,189
Robert S. Purgason	2013		448,269		581,050		250,221		—		263,899		—		40,700		1,584,139
Chief Operating Officer	2012		423,558		551,850		250,082		—		134,711		—		168,567		1,528,768
Chief Operating Officer	2011		374,760		352,500		205,646		—		72,534		—		109,507		1,114,947
David C. Shiels	2013		398,462		226,450		200,111		—		131,949		—		35,190		992,162
Chief Financial Officer	2012		373,750		200,750		200,138		—		67,355		—		119,351		961,344
Chief Financial Officer	2011		329,606		151,000		205,646		—		36,267		—		267,718		990,237
Walter Bennett	2013		311,385		212,450		405,188		—		—		—		18,030		947,053
Senior Vice President – Western Operations
John D. Seldenrust	2013		371,077		351,650		315,180		—		—		—		24,906		1,062,813
Senior Vice President – Eastern Operations

The following table sets forth information concerning grants of plan-based awards made to the named executive officers during 2013.

Name	Grant Date		Approval Date (1)		Estimated Future Payout Under Non- Equity Incentive Plan Awards – Target ($)		All Other Stock Awards: Number of Shares of Stock or Units (#)(2)		Grant Date Fair Value of Stock Awards ($)(3)
J. Mike Stice		January 2, 2013		December 13, 2012	$	—		90,380	$	3,112,687
		July 10, 2013		June 20, 2013		—		3,260		150,188
									$	3,262,875
		—		—		—
		—		—		—
Robert S. Purgason		January 2, 2013		December 13, 2012		—		5,085	$	175,127
		July 10, 2013		June 20, 2013		—		1,630		75,094
									$	250,221
		—		—		—
		—		—		—
David C. Shiels		January 2, 2013		December 13, 2012		—		3,630	$	125,017
		July 10, 2013		June 20, 2013		—		1,630		75,094
									$	200,111
		—		—		—
		—		—		—
Walter Bennett		January 2, 2013		December 13, 2012				3,050	$	105,042
		July 10, 2013		June 20, 2013				6,515		300,146
									$	405,188
		—		—		—
		—		—		—
John D. Seldenrust		January 2, 2013		December 13, 2012				5,085	$	175,127
		July 10, 2013		June 20, 2013				3,040		140,053
									$	315,180
		—		—		—
		—		—		—

The following table reflects outstanding phantom unit awards as of December 31, 2013, for each of the named executive officers 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 3, 2011		3,750		212,175
		July 1, 2011		5,602		316,961
		January 3, 2012		25,676		1,452,748
		July 2, 2012		7,102		401,831
		January 2, 2013		90,380		5,113,700
		July 10, 2013		3,260		184,451
Robert S. Purgason		January 3, 2011		2,500		141,450
		July 1, 2011		1,094		61,899
		January 3, 2012		1,927		109,030
		July 2, 2012		4,743		268,359
		January 2, 2013		5,085		287,709
		July 10, 2013		1,630		92,225
David C. Shiels		January 3, 2011		2,500		141,450
		July 1, 2011		1,094		61,899
		January 3, 2012		1,927		109,030
		July 2, 2012		3,390		191,806
		January 2, 2013		3,630		205,385
		July 10, 2013		1,630		92,225
Walter Bennett		January 2, 2013		3,050		172,569
		July 10, 2013		6,515		368,619
John D. Seldenrust		January 3, 2011		787		44,528
		July 1, 2011		547		30,949
		January 3, 2012		753		42,605
		July 2, 2012		1,582		89,510
		January 2, 2013		5,085		287,709
		July 10, 2013		3,040		172,003

Employment Agreements. As discussed under “Compensation Discussion and Analysis” above, each of the named executive officers is a party to an employment agreement with our general partner, each of which became effective January 1, 2013, 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 participated were 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 the arrangements in effect during calendar year 2013.

J. Mike Stice Employment Agreement. Mr. Stice's employment agreement provides for certain change of control and termination benefits in the event of a termination of Mr. Stice's employment under certain circumstances.

Upon a termination of his employment without “cause” or for a “good reason condition” (each as defined in the employment agreement), subject to his execution of a release, Mr. Stice is entitled to receive an amount equal to (i) 200% of his then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination. If such termination occurs within two years after a “change of control” (as defined in the employment agreement), Mr. Stice is entitled to receive (in lieu of the severance benefits described above) an amount equal to (a) 250% of the sum of (i) his then-current annual base salary and (ii) the most recent actual annual bonus (or, if the most recent annual bonus was paid semi-annually, the two most recent semi-annual bonuses) paid to Mr. Stice during the twelve-month period preceding the change of control, plus (b) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination.

Upon a termination of Mr. Stice’s employment due to his death or incapacity, subject (in the case of his incapacity) to the execution of a release, Mr. Stice (or his estate, as applicable) is entitled to receive an amount equal to (i) 100% of his then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum following such termination. Upon any other termination of employment (including a termination for “cause” or due to the expiration or non-renewal of the employment term), Mr. Stice will be entitled to receive only accrued but unpaid vacation through the date of termination. However, Mr. Stice may be entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our general partner’s Severance Program (as defined below), which is described in more detail below under “Severance Program.”

Mr. Stice’s employment agreement contains confidentiality restrictions effective during and after his employment and non-solicitation covenants effective during employment and for one year (or six months in the case of a termination due to the expiration of the employment term) following the termination of his employment.

David C. Shiels and Robert S. Purgason Employment Agreements. Mr. Shiels’ and Mr. Purgason’s employment agreements with our general partner provide for certain termination benefits in the event of termination under certain specified circumstances.

Upon a termination of employment without “cause” or for a “good reason condition” (each as defined in the applicable employment agreement), subject to the execution of a release, each of Messrs. Purgason and Shiels are entitled to receive an amount equal to (i) 100% of the executive’s then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination. If such termination occurs within two years after a “change of control” (as defined in the applicable employment agreement), each of Messrs. Purgason and Shiels are entitled to receive (in lieu of the severance benefits described above) an amount equal to (a) 100% of the sum of (i) the executive’s then-current annual base salary and (ii) the most recent actual annual bonus (or, if the most recent annual bonus was paid semi-annually, the two most recent semi-annual bonuses) paid to the executive during the twelve-month period preceding the change of control, plus (b) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination.

Upon a termination of employment due to the executive’s death or incapacity, subject (in the case of incapacity) to the execution of a release, each of Messrs. Purgason and Shiels (or their estates, as applicable) is entitled to receive an amount equal to (i) 100% (in the case of death) or 50% (in the case of incapacity), as applicable, of the executive’s then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum following such termination. Upon any other termination (including a termination for “cause” or due to the non-renewal of the employment term), each of Messrs. Purgason and Shiels will be entitled to receive only accrued but unpaid vacation through the date of termination. However, Messrs. Purgason and Shiels may be entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our Severance Program, which is described in more detail below under “Severance Program.”

Each employment agreement also contains confidentiality restrictions effective during and after the executive’s employment and non-solicitation covenants effective during employment and for one year following the termination of the executive’s employment.

Walter Bennett and John D. Seldenrust Employment Agreements. Mr. Bennett’s and Mr. Seldenrust’s employment agreements with our general partner provide for certain termination benefits in the event of termination under certain specified circumstances.

Upon a termination of employment without “cause” or for a “good reason condition” (each as defined in the applicable employment agreement), subject to the execution of a release, each of Messrs. Bennett and Seldenrust are entitled to receive an amount equal to (i) 26 weeks of the executive’s then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination. If such termination occurs within two years after a “change of control” (as defined in the applicable employment agreement), each of Messrs. Bennett and Seldenrust are entitled to receive (in lieu of the severance benefits described above) an amount equal to (a) the sum of (i) 26 weeks of the executive’s then-current annual base salary and (ii) the most recent annual bonus (or, if the most recent annual bonus was paid semi-annually, the two most recent semi-annual bonuses) paid to the executive during the twelve-month period preceding the change of control, plus (b) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination.

Upon a termination of employment due to the executive’s death or incapacity, subject (in the case of incapacity) to the execution of a release, each of Messrs. Bennett and Seldenrust (or their estates, as applicable) is entitled to receive an amount equal to (i) 52 weeks (in the case of death) or 26 weeks (in the case of incapacity), as applicable, of the executive’s then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum following such termination. Upon any other termination (including a termination for “cause” or due to the non-renewal of the employment term), each of Messrs. Bennett and Seldenrust will be entitled to receive only accrued but unpaid vacation through the date of termination. However, Messrs. Bennett and Seldenrust may be entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our Severance Program, which is described in more detail below under “Severance Program.”

Severance Program. Our general partner maintains the Access Midstream Partners GP, L.L.C. Employee Severance Program (the “Severance Program”), which provides certain severance payments and benefits to eligible employees, including our named executive officers, upon specified terminations of employment. Specifically, upon an involuntary termination of employment due to a job elimination, subject to the execution of a release and continued compliance with certain confidentiality obligations, each eligible employee is entitled to receive: (i) an amount in cash equal to eight weeks (or twenty-six weeks for directors and senior directors) of the participant’s base salary (the “Severance Payment”), (ii) payment or reimbursement for continued healthcare of COBRA coverage for eight weeks (or twenty-six weeks for directors and senior directors) following termination, (iii) payment for post-termination outplacement services, and (iv) full accelerated vesting of any of then-unvested awards of restricted units held by the participant (collectively, (ii) through (iv), the “Severance Benefits”).

However, employees who have entered into individual employment agreements with our general partner, including our named executive officers, are eligible to receive Severance Benefits under the Severance Program only to the extent that the applicable employment agreement does not provide the employee with the same type of severance benefits (i.e., healthcare or COBRA payment or reimbursement, outplacement benefits and/or equity award acceleration, as applicable)

provided under the Severance Program. Additionally, such employees, including our named executive officers, are eligible to receive the cash Severance Payment under the Severance Program only to the extent that the cash Severance Payment under the Severance Program is greater than the cash severance payments provided under the employment agreement.

MICP. Messrs. Stice, Shiels and Purgason are participants in the MICP. Mr. Stice holds awards granted under the MICP in 2012, and Messrs. Shiels and Purgason hold awards granted under the MICP in 2010 and 2012. Under the MICP, if a participant’s employment terminates for any reason prior to a payment date, other than due to (i) his death, disability, (ii) involuntary termination by the employer other than for “cause” (as defined in the MICP), or (iii) by the participant for a “good reason” (as defined in the MICP) (each such event in (i), (ii) and (iii), a “Qualified Termination”), then the participant’s award will be automatically forfeited on his or her termination of employment, to the extent then unpaid. If, however, a participant’s termination of employment prior to a payment date 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 quarters that have been completed as of the participant’s termination date, and (ii) at the end of the applicable five-year period, (a) with respect to the 2012 MICP awards, the full amount of the participant’s Equity Uplift Component (if any) and (b) with respect to the 2010 MICP awards, a pro-rated amount of the participant’s Equity Uplift Component (if any) (in each case, except as otherwise described below in connection with a change of control). Pursuant to a December 2012 amendment to Mr. Purgason’s 2010 award under the MICP, a nonrenewal of his employment term under his new employment agreement with our general partner will also be treated as a Qualifying Termination under the MICP for purposes of his 2010 award. 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.

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 annual installments attributable to fiscal quarters then completed and (ii) with respect to the Equity Uplift Component, an amount based on the increase in the value of our common units as of the change of control date over the value of our common units at the award commencement date. A participant who has incurred a Qualified Termination prior to the change of control will receive, with respect to the Equity Uplift Component (instead of the amounts due under clause (ii) above), 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. Stice, Shiels, Purgason, Bennett and Seldenrust under each the above described arrangements if such termination events had been triggered as of December 31, 2013.

J. Mike Stice - Executive Benefits and Payments Upon Separation	Termination without Cause		Change of Control		Retirement		Incapacity of Executive		Death of Executive
Compensation:
Cash Severance	$	1,500,000	$	3,750,000	$	—	$	750,000	$	750,000
Acceleration of Equity Compensation:
Phantom Unit Awards⁽¹⁾		—		7,681,867		—		—		—
Non-Equity Incentive Compensation:
Management Incentive Compensation Plan⁽²⁾		32,011,950		32,011,950		—		32,011,950		32,011,950
Benefits and Perquisites:
Accrued Vacation Pay		28,846		28,846		28,846		28,846		28,846
Total	$	33,540,796	$	43,472,663	$	28,846	$	32,790,796	$	32,790,796

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	$	450,000	$	1,000,000	$	—	$	225,000	$	450,000
Acceleration of Equity Compensation:
Phantom Unit Awards⁽¹⁾		—		960,672		—		—		—
Non-Equity Incentive Compensation:
Management Incentive Compensation Plan⁽²⁾		19,953,445		22,210,259		—		19,953,445		19,953,445
Benefits and Perquisites:
Accrued Vacation Pay		—		—		—		—		—
Total	$	20,403,445	$	24,170,931	$	—	$	20,178,445	$	20,403,445

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	$	415,000	$	615,000	$	—	$	207,500	$	415,000
Acceleration of Equity Compensation:
Phantom Unit Awards⁽¹⁾		—		801,795		—		—		—
Non-Equity Incentive Compensation:
Management Incentive Compensation Plan⁽²⁾		9,976,722		11,105,130		—		9,976,722		9,976,722
Benefits and Perquisites:
Accrued Vacation Pay		13,575		13,575		13,575		13,575		13,575
Total	$	10,405,297	$	12,535,500	$	13,575	$	10,197,797	$	10,405,297

Officers or employees of GIP, Williams, Chesapeake and our general partner 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. Such compensation 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.

On January 3, 2014, each of Messrs. Daberko, Berry and Frederickson and Ms. Kelly was awarded 915 phantom units, 229 of which were immediately vested.

The following table sets forth the compensation earned by the directors of our general partner in 2013:

Name	Fees Earned or Paid in Cash ($)		Stock Awards ($)(1)		Option Awards ($)		All Other Compensation ($)(2)		Total ($)
David A. Daberko		100,000		50,110		—		1,676		151,786
Alan S. Armstrong		—		—		—		—		—
William B. Berry⁽³⁾		60,000		51,659		—		—		111,659
William J. Brilliant		—		—		—		—		—
Don R. Chappel		—		—		—		—		—
James J. Cleary⁽⁴)		—		—		—		—		—
Domenic J. (“Nick”) Dell’Osso		—		—		—		—		—
Philip A. Frederickson		80,000		50,110		—		1,676		131,786
Matthew C. Harris⁽⁴⁾		—		—		—		—		—
Suedeen G. Kelly		80,000		50,110		—		1,676		131,786
Robert S. Purgason		—		—		—		—		—
James E. Scheel		—		—		—		—		—
J. Mike Stice		—		—		—		—		—
William A. Woodburn.		—		—		—		—		—

In 2013, Ms. Kelly and Messrs. Armstrong, Chappel, Daberko, Frederickson, Harris and Woodburn served on the compensation committee of our general partner’s board of directors. Ms. Kelly was replaced as the chairman by Mr. Harris effective March 14, 2013. Mr. Harris was replaced as the chairman by Mr. Woodburn effective October 24, 2013.

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.”

The following tables set forth the beneficial ownership of our common units and other classes of equity that, unless otherwise noted, as of February 19, 2014, are held by:

The following table sets forth information with respect to the securities that may be issued under the LTIP as of December 31, 2013. For more information regarding the LTIP, which did not require approval by our unitholders, please see “Item 11. Executive Compensation—Long-Term Incentive Plan.”

At February 19, 2014, the GIP II Entities owned 57,942,361 common units and 6,276,661 Class B units representing an aggregate 31.2 percent limited partner interest in us, and Williams owned 40,137,695 common units and 6,276,661 Class B units representing an aggregate 22.6 percent limited partner interest in us. In addition, the GIP II Entities and Williams, through their joint ownership of Access 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.

The following table summarizes the distributions and payments made by us to our general partner and its affiliates in connection with our ongoing operation and any liquidation of Access Midstream Partners, L.P. These distributions and payments were determined by and among affiliated entities.

In June 2012, Chesapeake sold all of its ownership interests in us and in our general partner; however, Mr. Dell’Osso, Executive Vice President and Chief Financial Officer of Chesapeake, remains on our board of directors. We set forth below a description of our transactions with Chesapeake entered into in 2013.

Access MLP Operating, LLC, our operating subsidiary, was party to an Operating Agreement with Mid-America Midstream Gas Services, LLC, a subsidiary of Chesapeake (“Mid-America”) whereby Access MLP Operating, LLC provided management and operational activities for Mid-America with respect to certain gas gathering systems in return for a management fee. The operating agreement expired on March 31, 2013. For the year ended December 31, 2013, Mid-America paid Access MLP Operating, LLC approximately $3.1 million under the operating agreement.

We are party to a services agreement with Chesapeake under which Chesapeake and its affiliates traditionally provided certain transition services, including legal, accounting, treasury, human resources, information technology and administrative services, to us and our general partner following the GIP Acquisition. Most of these transition services terminated effective December 31, 2013. However, in accordance with the provisions of the services agreement, we extended the term for the provision of certain technology-related services through March 2014 and certain field communication support services through June 2014. For the year ended December 31, 2013, we paid Chesapeake and its affiliates approximately $7.1 million under the services agreement.

We are party to several gas gathering agreements with certain subsidiaries of Chesapeake under which we provide gathering and related services on our gathering systems in the Eagle Ford Shale region, Haynesville Shale region, Marcellus Shale region, Niobrara Shale region and Utica Shale region. For the year ended December 31, 2013, we received fees totaling $1.0 billion in the aggregate for providing services under these agreements.

We are party to four compression agreements with MidCon Compression, LLC (“MidCon Compression”), a wholly owned indirect subsidiary of Chesapeake, pursuant to which MidCon Compression has agreed to provide compression equipment that we use to compress gas gathered on our gathering systems and provide certain related services. In return for MidCon Compression’s provision 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. For the year ended December 31, 2013, we paid MidCon Compression fees totaling $109.3 million in the aggregate for providing compression equipment under these agreements.

We are party to a master recoupment, netting and setoff agreement with Chesapeake and certain of its subsidiaries that provides for the netting of fees, liquidated damages and other charges between the parties to certain “covered agreements,” including our gas gathering agreements with Chesapeake with respect to the Eagle Ford, Haynesville, Niobrara, Marcellus and Utica Shale regions and our services 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.

In connection with our services agreement, we reimburse GIP for certain costs incurred by GIP in connection with assisting us in the operation of our business. We reimbursed GIP $0.4 million for the year ended December 31, 2013 under this agreement.

We are party to an amended and restated registration rights agreement with Williams and the GIP II Entities pursuant to which we have granted each of Williams and the GIP II Entities and certain of their affiliates certain demand and “piggyback” registration rights. Under the amended and restated registration rights agreement, each of Williams and

the GIP II Entities 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 units, subordinated units, Class B units, Class C 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 Williams and the GIP II Entities 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.

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 Access Midstream Ventures’ 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.

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 exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Williams, the GIP II Entities and Access 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:

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.

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.”

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:

Audit fees are primarily for audit of the Partnership’s consolidated financial statements, reviews of the Partnership’s financial statements included in the Form 10-Qs, comfort letters and other filings.

Audit-related fees for the year ended December 31, 2012 include the audit and review, respectively, of the Marcellus gas gathering systems financial statements for the 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.

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 2013, 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, 2013.


		Incorporated by Reference
Exhibit Number	Exhibit Description	Form		SEC File Number		Exhibit		Filing Date		Filed Herewith	Furnished Herewith
2.1	Asset Purchase Agreement, dated as of December 16, 2010, 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.		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
2.3	Unit Purchase Agreement, dated as of December 11, 2012, by and among Chesapeake Midstream Development, L.L.C. and Access Midstream Partners, L.P.		8-K		001-34831		2.1		12/12/2012
2.4	Subscription Agreement, dated as of December 11, 2012, by and among Access Midstream Partners, L.P., Access Midstream Partners GP, L.L.C., GIP II Hawk Holdings Partnership, L.P. and The Williams Companies, Inc.		8-K		001-34831		2.2		12/12/2012
3.1	Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P.		S-1		333-164905		3.1		02/16/2010
3.1.1	Certificate of Amendment to the Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P.		8-K		001-34831		3.1		07/30/2012


		Incorporated by Reference
Exhibit Number	Exhibit Description	Form		SEC File Number		Exhibit		Filing Date		Filed Herewith	Furnished Herewith
3.1.2	Composite Certificate of Limited Partnership of Access Midstream Partners, L.P.		8-K		001-34831		3.2		07/30/2012
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
3.2.1	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. dated as of July 24, 2012		8-K		001-34831		3.3		07/30/2012
3.2.2	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of December 20, 2012		8-K		001-34831		3.1		12/26/2012
3.2.3	Composite Agreement of Limited Partnership of Access Midstream Partners, L.P.		10-K		001-34831		3.2.3		02/25/2013
3.3	Certificate of Formation of Chesapeake Midstream GP, L.L.C.		S-1		333-164905		3.3		02/16/2010
3.3.1	Certificate of Amendment to the Certificate of Formation of Chesapeake Midstream GP, L.L.C.		8-K		001-34831		3.5		07/30/2012
3.3.2	Composite Certificate of Formation of Access Midstream Partners GP, L.L.C.		8-K		001-34831		3.6		07/30/2012
3.4	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	Supplemental Indenture, dated as of January 7, 2013, 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		4.2		08/19/2013

Incorporated by Reference

Exhibit
Number

Exhibit Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

4.3

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

4.4

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

4.5

Supplemental Indenture and Amendment – Subsidiary guarantee, dated as of January 7, 2013, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee

4.6

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

4.7

Indenture, dated as of December 19, 2012, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee

8-K

001-34831

4.1

12/19/2012

4.8

First Supplemental Indenture, dated as of December 19, 2012, among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee

8-K

001-34831

4.2

12/19/2012

4.9

Second Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of January 7, 2013, by among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee

4.10

Amended and Restated Registration Rights Agreement, dated as of December 20, 2012, by and among Access Midstream Partners, L.P., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P., GIP II Eagle Holdings Partnership, L.P., GIP II Hawk Holdings Partnership, L.P. and The Williams Companies, Inc.

8-K

001-34831

4.1

12/26/2012

Incorporated by Reference

Exhibit
Number

Exhibit Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

10.1

Omnibus Agreement, dated August 3, 2010, by and among Chesapeake Midstream Holdings, L.L.C., Chesapeake Midstream Ventures, L.L.C. and Chesapeake Midstream Partners, L.P.

8-K

001-34831

10.1

08/05/2010

10.1.1

Amendment to Omnibus Agreement, dated June 15, 2012, by and among Chesapeake Midstream Holdings, L.L.C., Chesapeake Midstream Ventures, L.L.C. and Chesapeake Midstream Partners, L.P.

8-K

001-34831

10.5

06/20/2012

10.2

Amended and Restated Services Agreement, dated August 3, 2013, 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.

8-K

001-34831

1.3

06/19/2012

10.2.1

Letter Agreement, dated June 15, 2012, by and among Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Partners, L.P., Chesapeake MLP Operating, L.L.C., Chesapeake Midstream Management, L.L.C., Chesapeake Operating, Inc., GIP A Holding (CHK), L.P., GIP B Holding (CHK), L.P. and GIP C Holding (CHK), L.P.

8-K

001-34831

10.2

07/06/2012

10.2.2

Amendment to Letter Agreement, dated June 29, 2012, by and among Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Partners, L.P., Chesapeake MLP Operating, L.L.C., Chesapeake Midstream Management, L.L.C., Chesapeake Operating, Inc., GIP A Holding (CHK), L.P., GIP B Holding (CHK), L.P. and GIP C Holding (CHK), L.P.

S-1

333-164905

10.18

07/20/2010

Incorporated by Reference

Exhibit
Number

Exhibit Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

10.2.3

Second Letter Amendment Agreement, dated as of December 20, 2012, amending that certain Letter Agreement, dated as of June 15, 2012, by and among Chesapeake Energy Corporation, Chesapeake Midstream Management, L.L.C., Chesapeake Operating, Inc., Access Midstream Partners GP, L.L.C. (f/k/a Chesapeake Midstream GP, L.L.C.), Access Midstream Partners, L.P. (f/k/a Chesapeake Midstream Partners,

L.P.), Access MLP Operating L.L.C. (f/k/a Chesapeake MLP Operating L.L.C.), GIP A Holding (CHK), L.P., GIP B Holding (CHK), L.P. and GIP C Holding (CHK), L.P.

10-K

001-34831

10.10.1

03/11/2011

10.6†

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

10.6.1†

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

10.6.2

Letter Agreement Amendment, dated April 13, 2012, 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.

10.7

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

10.8†

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

10.8.1†

First Amendment to Gas Gathering Agreement, Dated July 5, 2011, 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.

Incorporated by Reference

Exhibit
Number

Exhibit Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

10.8.2†

Amendment to Gas Gathering Agreement, dated June 1, 2013, effective as of January 1, 2013, 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.

10.8.3†

Agreement to Implement Lower Pressure Service – Springridge GGA, dated November 14, 2013, 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.

10.9†

Eagle Ford Gas Gathering Contract, dated effective July 1, 2012, by and among Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Chesapeake Exploration, L.L.C. and Mockingbird Midstream Gas Services, L.L.C.

10-K

001-34831

10.9

02/25/2013

10.10†

Haynesville Gas Gathering Contract, dated effective July 1, 2012, by and among Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Chesapeake Louisiana, L.P., Empress, L.L.C. and Louisiana Midstream Gas Services, L.L.C.

10-K

001-34831

10.10

02/25/2013

10.11

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

10.11.1†

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

10.12†

Compression Agreement, effective as of September 30, 2009, between MidCon Compression, LLC and Chesapeake MLP Operating, L.L.C.

10-K

001-34831

10.12

02/25/2013

10.13†

Compression Agreement, effective as of January 1, 2011, between MidCon Compression, L.L.C. and Chesapeake Midstream Operating, L.L.C.

10-K

001-34831

10.13

02/25/2013

Incorporated by Reference

Exhibit
Number

Exhibit Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

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 Access Midstream Partners GP, L.L.C. Management Incentive Compensation Plan, dated as of December 20, 2012

8-K

001-34831

10.5

12/27/2012

10.15.1*

Form of Award Agreement under Amended and Restated Access Midstream Partners GP, L.L.C. Management Incentive Compensation Plan

8-K

001-34831

10.6

12/27/2012

10.15.2*

Award Agreement under Chesapeake Midstream Management Incentive Compensation Plan - Robert S. Purgason

S-1

333-164905

10.20

07/06/2010

10.15.3*

Award Agreement under Chesapeake Midstream Management Incentive Compensation Plan – David C. Shiels

S-1

333-164905

10.21

07/06/2010

10.15.4*

First Amendment to Award Agreement, effective as of December 20, 2012, by and between Access Midstream Partners GP, L.L.C. and Robert S. Purgason

8-K

001-34831

10.7

12/27/2012

10.16*

Amended and Restated Employment Agreement of J. Mike Stice, dated as of November 10, 2011

10-K

001-34831

10.16

02/29/2012

10.16.1*

Amendment to Employment Agreement of J. Mike Stice, dated as of December 22, 2011

10-K

001-34831

10.16.1

02/29/2012

10.17

Employment Agreement, effective as of January 1, 2013, between Access Midstream Partners GP, L.L.C. and J. Mike Stice

8-K

001-34831

10.1

12/27/2012

10.18*

Employment Agreement, effective as of January 1, 2013, between Access Midstream Partners GP, L.L.C. and Robert S. Purgason

8-K

001-34831

10.3

12/27/2012

10.19*

Employment Agreement, effective as of January 1, 2013, between Access Midstream Partners GP, L.L.C. and David C. Shiels

8-K

001-34831

10.2

12/27/2012

Incorporated by Reference

Exhibit
Number

Exhibit Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

10.20

Second Amended and Restated Credit Agreement, dated as of May 13, 2013, by and among Access MLP Operating, L.L.C., as the Borrower, Access Midstream Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and the Issuing Lender, and the other lenders party thereto.

8-K

001-34831

10.1

05/14/2013

10.21

Non-Solicitation Agreement, dated as of December 20, 2012, among Access Midstream Partners, L.P., Chesapeake Midstream Development, L.L.C., Chesapeake Operating, Inc., Chesapeake Energy Marketing, Inc. and Chesapeake Energy Corporation.

8-K

001-34831

10.1

12/26/2012

10.22*

Assumption Agreement, dated December 20, 2012, between Chesapeake Midstream Management, L.L.C. and Access Midstream Partners GP, L.L.C.

8-K

001-34831

10.4

12/27/2012

10.23*

Access Midstream Partners GP, L.L.C. Employee Severance Program, effective as of January 1, 2013.

8-K

001-34831

10.8

12/27/2012

10.24

Termination Agreement, dated as of December 20, 2012, by and among Chesapeake Midstream Development, L.L.C. (successor to Chesapeake Midstream Holdings, L.L.C.), Access Midstream Ventures, L.L.C. (f/k/a Chesapeake Midstream Ventures, L.L.C.), Access Midstream Partners, L.P. (f/k/a Chesapeake Midstream Partners, L.P.), Chesapeake Energy Marketing, Inc., Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P., Appalachia Midstream Services, L.L.C., Chesapeake Appalachia, L.L.C., Magnolia Midstream Gas Services, L.L.C., Access MLP Operating, L.L.C. (f/k/a Chesapeake Midstream Partners, L.L.C.), and Empress, L.L.C.

8-K

001-34831

10.3

12/26/2012

12.1

Ratio of Earnings to Fixed Charges

21.1

Subsidiaries of Access Midstream Partners, L.P.

23.1

Consent of PricewaterhouseCoopers, LLP

Incorporated by Reference

Exhibit
Number

Exhibit Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

31.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 302

of the Sarbanes-Oxley Act of 2002.

31.2

David C. Shiels, Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

David C. Shiels, Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

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.

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.

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form		SEC File Number		Exhibit		Filing Date		Filed Herewith	Furnished Herewith
2.1	Asset Purchase Agreement, dated as of December 16, 2010, 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.		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
2.3	Unit Purchase Agreement, dated as of December 11, 2012, by and among Chesapeake Midstream Development, L.L.C. and Access Midstream Partners, L.P.		8-K		001-34831		2.1		12/12/2012
2.4	Subscription Agreement, dated as of December 11, 2012, by and among Access Midstream Partners, L.P., Access Midstream Partners GP, L.L.C., GIP II Hawk Holdings Partnership, L.P. and The Williams Companies, Inc.		8-K		001-34831		2.2		12/12/2012
3.1	Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P.		S-1		333-164905		3.1		02/16/2010
3.1.1	Certificate of Amendment to the Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P.		8-K		001-34831		3.1		07/30/2012
3.1.2	Composite Certificate of Limited Partnership of Access Midstream Partners, L.P.		8-K		001-34831		3.2		07/30/2012
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

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form		SEC File Number		Exhibit		Filing Date		Filed Herewith	Furnished Herewith
3.2.1	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. dated as of July 24, 2012		8-K		001-34831		3.3		07/30/2012
3.2.2	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of December 20, 2012		8-K		001-34831		3.1		12/26/2012
3.2.3	Composite Agreement of Limited Partnership of Access Midstream Partners, L.P.		10-K		001-34831		3.2.3		02/25/2013
3.3	Certificate of Formation of Chesapeake Midstream GP, L.L.C.		S-1		333-164905		3.3		02/16/2010
3.3.1	Certificate of Amendment to the Certificate of Formation of Chesapeake Midstream GP, L.L.C.		8-K		001-34831		3.5		07/30/2012
3.3.2	Composite Certificate of Formation of Access Midstream Partners GP, L.L.C.		8-K		001-34831		3.6		07/30/2012
3.4	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	Supplemental Indenture, dated as of January 7, 2013, 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		4.2		08/19/2013
4.3	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

Incorporated by Reference

Exhibit
Number

Exhibit
Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

4.4

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

4.5

4.6

8-K

001-34831

4.2

01/11/2012

4.7

8-K

001-34831

4.1

12/19/2012

4.8

8-K

001-34831

4.2

12/19/2012

4.9

4.10

8-K

001-34831

4.1

12/26/2012

Incorporated by Reference

Exhibit
Number

Exhibit
Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

10.1

Omnibus Agreement, dated August

3, 2010, by and among Chesapeake Midstream Holdings, L.L.C., Chesapeake Midstream Ventures, L.L.C. and Chesapeake Midstream Partners, L.P.

8-K

001-34831

10.1

08/05/2010

10.1.1

Amendment to Omnibus Agreement, dated June 15, 2012, by and among Chesapeake Midstream Holdings, L.L.C., Chesapeake Midstream Ventures, L.L.C. and Chesapeake Midstream Partners, L.P.

8-K

001-34831

10.5

06/20/2012

10.2

8-K

001-34831

10.2

08/05/2010

10.2.1

8-K

001-34831

10.2

06/20/2012

10.2.2

8-K

001-34831

10.1

07/06/2012

Incorporated by Reference

Exhibit
Number

Exhibit
Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

10.2.3

Operating, Inc., Access Midstream Partners GP, L.L.C. (f/k/a Chesapeake Midstream GP, L.L.C.), Access Midstream Partners, L.P. (f/k/a Chesapeake Midstream Partners, L.P.), Access MLP Operating L.L.C. (f/k/a Chesapeake MLP Operating L.L.C.), GIP A Holding (CHK), L.P., GIP B Holding (CHK), L.P. and GIP C Holding (CHK), L.P.

8-K

001-34831

10.2

12/26/2012

10.3

Investor Rights Agreement, dated June 15, 2012, by and among Chesapeake Midstream Ventures, 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., GIP II Eagle 1 Holding, L.P., GIP II Eagle 2 Holding, L.P., GIP II Eagle 3 Holding, L.P. and GIP II Eagle 4 Holding, L.P.

8-K

001-34831

1.3

06/19/2012

10.4

Amended and Restated Management Rights Agreement, dated June 29, 2012, by and among GIP II-B Eagle AIV 1, L.P., GIP II Eagle Holdings Partnership, L.P., GIP II Eagle 2 Holding, L.P., GIP II Eagle Acquisition Holdings GP, LLC, Chesapeake Midstream Ventures, L.L.C., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Partners, L.P. and Chesapeake MLP Operating, L.L.C.

8-K

001-34831

10.2

07/06/2012

10.5*

Chesapeake Midstream Long-Term Incentive Plan

S-1

333-164905

10.18

07/20/2010

10.5.1*

Form of Restricted Unit Award Agreement for Long-Term Incentive Plan

10-K

001-34831

10.10.1

03/11/2011

10.6†

S-1

333-164905

10.2

07/26/2010

Incorporated by Reference

Exhibit
Number

Exhibit
Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

10.6.1†

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

10.6.2

10.7

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

10.8†

10-K

001-34831

10.13

03/11/2011

10.8.1†

10.8.2†

Incorporated by Reference

Exhibit
Number

Exhibit
Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

10.8.3†

Louisiana L.P.

10.9†

10-K

001-34831

10.9

02/25/2013

10.10†

10-K

001-34831

10.10

02/25/2013

10.11

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

10.11.1†

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

10.12†

Compression Agreement, effective as of September 30, 2009, between MidCon Compression, LLC and Chesapeake MLP Operating, L.L.C.

10-K

001-34831

10.12

02/25/2013

10.13†

Compression Agreement, effective as of January 1, 2011, between MidCon Compression, L.L.C. and Chesapeake Midstream Operating, L.L.C.

10-K

001-34831

10.13

02/25/2013

10.14†

S-1

333-164905

10.4

07/26/2010

Incorporated by Reference

Exhibit
Number

Exhibit
Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

10.15*

Amended and Restated Access Midstream Partners GP, L.L.C. Management Incentive Compensation Plan, dated as of

December 20, 2012

8-K

001-34831

10.5

12/27/2012

10.15.1*

Form of Award Agreement under Amended and Restated Access Midstream Partners GP, L.L.C. Management Incentive Compensation Plan

8-K

001-34831

10.6

12/27/2012

10.15.2*

Award Agreement under Chesapeake Midstream Management Incentive Compensation Plan - Robert S. Purgason

S-1

333-164905

10.20

07/06/2010

10.15.3*

Award Agreement under Chesapeake Midstream Management Incentive Compensation Plan – David C. Shiels

S-1

333-164905

10.21

07/06/2010

10.15.4*

First Amendment to Award Agreement, effective as of December 20, 2012, by and between Access Midstream Partners GP, L.L.C. and Robert S. Purgason

8-K

001-34831

10.7

12/27/2012

10.16 *

Amended and Restated Employment Agreement of J. Mike Stice, dated as of November 10, 2011

10-K

001-34831

10.16

02/29/2012

10.16.1 *

Amendment to Employment Agreement of J. Mike Stice, dated as of December 22, 2011

10-K

001-34831

10.16.1

02/29/2012

10.17

Employment Agreement, effective as of January 1, 2013, between Access Midstream Partners GP, L.L.C. and J. Mike Stice

8-K

001-34831

10.1

12/27/2012

10.18*

Employment Agreement, effective as of January 1, 2013, between Access Midstream Partners GP, L.L.C. and Robert S. Purgason

8-K

001-34831

10.3

12/27/2012

10.19*

Employment Agreement, effective as of January 1, 2013, between Access Midstream Partners GP, L.L.C. and David C. Shiels

8-K

001-34831

10.2

12/27/2012

Incorporated by Reference

Exhibit
Number

Exhibit
Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

10.20

the other lenders party thereto.

8-K

001-34831

10.1

05/14/2013

10.21

8-K

001-34831

10.1

12/26/2012

10.22*

Assumption Agreement, dated December 20, 2012, between Chesapeake Midstream Management, L.L.C. and Access Midstream Partners GP, L.L.C.

8-K

001-34831

10.4

12/27/2012

10.23*

Access Midstream Partners GP, L.L.C. Employee Severance Program, effective as of January 1, 2013.

8-K

001-34831

10.8

12/27/2012

10.24

8-K

001-34831

10.3

12/26/2012

12.1

Ratio of Earnings to Fixed Charges

21.1

Subsidiaries of Access Midstream Partners, L.P.

23.1

Consent of PricewaterhouseCoopers, LLP

31.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Incorporated by Reference

Exhibit
Number

Exhibit
Description

Form

SEC File
Number

Exhibit

Filing
Date

Filed
Herewith

Furnished
Herewith

31.2

David C. Shiels, Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley

Act of 2002.

32.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

David C. Shiels, Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document


Delaware		80-0534394
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
525 Central Park Drive
Oklahoma City, Oklahoma		73105
(Address of principal executive offices)		(Zip Code)


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

PART I		Page
Item 1.	Business	1
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	34
Item 2.	Properties	34
Item 3.	Legal Proceedings	35
Item 4.	Mine Safety Disclosures	35
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	36
Item 6.	Selected Financial Data	38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	67
Item 8.	Financial Statements and Supplementary Data	68
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	97
Item 9A.	Controls and Procedures	97
Item 9B.	Other Information	97
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	98
Item 11.	Executive Compensation	105
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	120
Item 13.	Certain Relationships and Related Transactions and Director Independence	122
Item 14.	Principal Accountant Fees and Services	126
PART IV
Item 15.	Exhibits and Financial Statement Schedules	127

	Common Units
	High		Low		Distribution per common unit
Year ended December 31, 2013
Fourth Quarter	$	57.48	$	46.66	$	0.5550
Third Quarter		49.29		44.75		0.5350
Second Quarter		48.74		38.00		0.4850
First Quarter		41.68		33.76		0.4675
Year ended December 31, 2012
Fourth Quarter	$	37.57	$	30.10	$	0.4500
Third Quarter		33.65		26.46		0.4350
Second Quarter		29.90		22.50		0.4200
First Quarter		31.19		27.59		0.4050

	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⁾	$	4,580,056	$	508,313	$	329,625	$	325,797	$	3,416,321
Capital leases		7,721		3,287		4,434		—		—
Operating leases		219,766		69,774		96,102		35,205		18,685
Total	$	4,807,543	$	581,374	$	430,161	$	361,002	$	3,435,006

Region	Location (State(s))	Average Throughput (Bcf/d) ⁽¹⁾		Approximate Length of Pipeline (Miles)		Gas Compression (Horsepower)
Barnett Shale	TX		1.045		859		150,945
Eagle Ford Shale	TX		0.263		870		93,847
Haynesville Shale	LA		0.669		582		20,195
Marcellus Shale	PA, WV		1.019		823		136,090
Niobrara Shale	WY		0.015		132		15,665
Utica Shale	OH		0.107		265		63,505
Mid-Continent	TX, OK, KS, AR		0.581		2,805		108,735
Total			3.699		6,336		588,982

	Year Ended December 31, 2013		Year Ended December 31, 2012
Revenue ($ in thousands)	$	234,801	$	140,541
Throughput (Bcf)		367.3		256.7
Operating Expenses ($ in thousands)	$	35,999	$	15,782
Expenses ($ per Mcf)		0.10		0.06

	Year Ended December 31, 2012
Revenues ($ in thousands)	$	140,541
Throughput (Bcf)		256.7
Operating expenses ($ in thousands)	$	15,782
Expenses ($ per Mcf)		0.06

	Years Ended December 31,
	2013			2012
	($ in thousands)
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	563,962		$	318,130
Investing activities	$	(1,556,418	)	$	(2,685,965	)
Financing activities	$	944,691		$	2,432,807

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

	Page
Management’s Report on Internal Control Over Financial Reporting	69
Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm	70
Consolidated Balance Sheets at December 31, 2013 and 2012	71
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011	72
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011	73
Consolidated Statements of Changes in Partners’ Capital for the Years Ended December 31, 2013, 2012 and 2011	74
Notes to Consolidated Financial Statements	75

	December 31, 2013				December 31, 2012
	Carrying amount		Fair Value (Level 2)		Carrying amount		Fair Value (Level 2)
			($ in thousands)
Financial liabilities
Revolving credit facility	$	343,500	$	343,500	$	—	$	—
Premium on 2021 Notes		5,730		5,730		—		—
2021 Notes		750,000		801,098		350,000		370,125
2022 Notes		750,000		804,848		750,000		810,000
2023 Notes		1,400,000		1,355,382		1,400,000		1,428,882

	Units			Value per Unit
Restricted units unvested at beginning of period		511,177		$	28.55
Granted		971,667		$	38.40
Vested		(101,023	)	$	27.40
Forfeited		(199,533	)	$	32.29
Restricted units unvested at end of period		1,182,288		$	36.11

	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	%

	Estimated Useful Lives (Years)		December 31, 2013			December 31, 2012
	($ in thousands)
Gathering systems		20	$	5,974,940		$	5,125,746
Other fixed assets		2 through 39		175,411			96,916
Total property, plant and equipment				6,150,351			5,222,662
Accumulated depreciation				(859,551	)		(590,614	)
Total net, property, plant and equipment			$	5,290,800		$	4,632,048

Property, plant and equipment	$	1,890,036
Intangible asset		263,262
Other		6,702
Total purchase price	$	2,160,000

	Year Ended December 31,		Year Ended December 31,
	2012		2011
	(in thousands)
Revenues, including revenue from affiliates	$	670,702	$	689,840
Net income	$	117,334	$	69,390
Net income attributable to Access Midstream Partners, L.P.	$	117,861	$	69,390
Net income per common unit – basic and diluted	$	0.72	$	0.49
Net income per subordinated unit – basic and diluted	$	0.74	$	0.49

	Net Ownership Interest				December 31, 2013		December 31, 2012
	($ in thousands)
Utica East Ohio Midstream LLC		49.00	%	$		471,891	$	125,416
Liberty gas gathering system		33.75	%			354,316		264,625
Panhandle gas gathering system		67.50				237,656		149,654
Victory gas gathering system		67.50				190,353		178,011
Rome gas gathering system		33.75				181,147		160,087
Overfield gas gathering system		67.50				125,959		101,339
Smithfield gas gathering system		67.50				107,009		82,347
Selbyville gas gathering system		67.50				73,463		65,354
Ranch Westex JV, LLC		33.33				36,060		35,012
Other gas gathering systems		various				158,749		135,966
Total investments in unconsolidated affiliates				$		1,936,603	$	1,297,811

	(in thousands)
2014	$	69,774
2015		54,058
2016		42,044
2017		26,274
2018		8,931
Thereafter		18,685
Future minimum lease payments	$	219,766

	December 31,
	2013
Computer software	$	9,370
Less: Accumulated amortization		(2,063	)
Net assets under capital lease	$	7,307

Fiscal Year	(in thousands)
2014	$	3,667
2015		3,667
2016		969
Less: Interest		(582	)
Net minimum lease payments under capital leases		7,721
Less: Current portion of net minimum lease payments		(3,287	)
Long-term portion of net minimum lease payments	$	4,434

Name	Age		Position with Access Midstream Partners GP, L.L.C.
J. Mike Stice		54	Chief Executive Officer and Director
Robert S. Purgason		57	Chief Operating Officer and Director
David C. Shiels		48	Chief Financial Officer
Walter Bennett		44	Senior Vice President – Western Operations
John D. Seldenrust		49	Senior Vice President – Eastern Operations
David A. Daberko		68	Chairman of the Board
Alan S. Armstrong		51	Director
William B. Berry		61	Director
William J. Brilliant		38	Director
Donald R. Chappel		62	Director
James J. Cleary		59	Director
Domenic J. Dell’Osso, Jr.		37	Director
Philip L. Frederickson		57	Director
Suedeen G. Kelly		62	Director
James E. Scheel		49	Director
William A. Woodburn		63	Director


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 Adjusted EBITDA, distributable 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

Name	401(k) Plan Matching Contributions ($)(a)		Distribution Equivalent Rights ($)(b)		Supplemental Life Insurance ($)(c)		Supplemental Accidental Death and Dismemberment Insurance ($)(d)		Tax Gross- Ups ($)(e)		Total ($)
J. Mike Stice		20,404		33,343		6,532		1,131		6,392		67,802
Robert S. Purgason		20,144		9,520		9,589		893		554		40,700
David C. Shiels		17,038		8,719		2,011		546		6,876		35,190
Walter Bennett		16,514		—		1,038		428		50		18,030
John D. Seldenrust		17,500		3,469		2,277		615		1,045		24,906

	Unit Awards
Name	Number of Units Acquired on Vesting (#) (1)		Value Realized on Vesting ($)
J. Mike Stice		15,603	$	602,463
Robert S. Purgason		4,023		165,006
David C. Shiels		3,571		143,898
Walter Bennett		—		—
John D. Seldenrust		1,448		59,878

Walter Bennett - Executive Benefits and Payments Upon Separation	Termination without Cause		Change of Control		Retirement		Incapacity of Executive		Death of Executive
Compensation:
Cash Severance	$	167,500	$	327,500	$	—	$	167,500	$	335,000
Acceleration of Equity Compensation:
Phantom Unit Awards⁽¹⁾		—		541,188		—		—		—
Benefits and Perquisites:
Accrued Vacation Pay		3,228		3,228		3,228		3,228		3,228
Total	$	170,728	$	871,916	$	3,228	$	170,728	$	338,228

John D. Seldenrust - Executive Benefits and Payments Upon Separation	Termination without Cause		Change of Control		Retirement		Incapacity of Executive		Death of Executive
Compensation:
Cash Severance	$	193,000	$	503,000	$	—	$	193,000	$	386,000
Acceleration of Equity Compensation:
Phantom Unit Awards⁽¹⁾		—		667,305		—		—		—
Benefits and Perquisites:
Accrued Vacation Pay		2,977		2,977		2,977		2,977		2,977
Total	$	195,977	$	1,173,282	$	2,977	$	195,977	$	388,977

Name and address of beneficial owner⁽¹⁾	Common units beneficially owned		Percentage of common units beneficially owned⁽²⁾
GIP II Entities⁽³⁾ 12 E. 49th Street, 38th Floor New York, NY 10017		57,942,361		30.6	%
Williams⁽⁴⁾ One Williams Center Tulsa, OK 74172		40,137,695		21.2	%
Tortoise Capital Advisors, LLC⁽⁵⁾ 11550 Ash Street, Suite 300 Leawood, Kansas 66211		10,258,823		5.4	%
Goldman Sachs Asset Management⁽⁶⁾ 200 West Street New York, NY 10282		5,835,817		3.1	%
ClearBridge Investments, LLC⁽⁷⁾ 620 8^th Avenue New York, NY 10018		4,324,450		2.3	%
J. Mike Stice		34,130		*	%
Robert S. Purgason		16,550		*	%
David C. Shiels		2,350		*	%
Walter Bennett		473		*	%
John D. Seldenrust		5,388		*	%
David A. Daberko		16,049		*	%

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⁾		—		—		2,159,669

Signature	Capacity	Date
/s/ J. MIKE STICE	Chief Executive Officer and Director (Principal Executive Officer)	February 21, 2014
J. Mike Stice		February 21, 2014
/s/ DAVID C. SHIELS	Chief Financial Officer (Principal Financial and Accounting Officer)	February 21, 2014
David C. Shiels		February 21, 2014
/s/ ROBERT S. PURGASON	Chief Operating Officer and Director	February 21, 2014
Robert S. Purgason
/s/ DAVID A. DABERKO	Chairman of the Board and Director	February 21, 2014
David A. Daberko
/s/ ALAN S. ARMSTRONG	Director	February 21, 2014
Alan S. Armstrong
/s/ WILLIAM B. BERRY	Director	February 21, 2014
William B. Berry
/s/ WILLIAM J. BRILLIANT	Director	February 21, 2014
William J. Brilliant
/s/ DONALD R. CHAPPEL	Director	February 21, 2014
Donald R. Chappel
/s/ JAMES J. CLEARY	Director	February 21, 2014
James J. Cleary
/s/ DOMENIC J. DELL’OSSO JR.	Director	February 21, 2014
Domenic J. Dell’Osso Jr.
/s/ PHILIP L. FREDERICKSON	Director	February 21, 2014
Philip L. Frederickson
/s/ SUEDEEN G. KELLY	Director	February 21, 2014
Suedeen G. Kelly
/s/ JAMES E. SCHEEL	Director	February 21, 2014
James E. Scheel
/s/ WILLIAM A. WOODBURN	Director	February 21, 2014
William A. Woodburn