ITEM 1. Business
Unless the context otherwise requires, references in this report to the “Partnership,” “we,” “our,” “us” or like terms, when used in a historical context, refer to the financial results of Chesapeake Midstream Partners, L.L.C. through the closing date of our initial public offering (“IPO”) on August 3, 2010 and to Access Midstream Partners, L.P. (NYSE: ACMP) and its subsidiaries thereafter. 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). “Chesapeake” refers to Chesapeake Energy Corporation (NYSE: CHK). “Total,” when discussing the upstream joint venture with Chesapeake, refers to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (NYSE: TOT, FP: FP), and when discussing our gas gathering agreement and related matters, refers to Total E&P USA, Inc. and Total Gas & Power North America, Inc., a wholly owned subsidiary of Total S.A.
General
We are a growth-oriented publicly traded Delaware limited partnership formed 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, 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 our Barnett Shale region in north-central Texas; our Eagle Ford Shale region in South Texas; our Haynesville Shale region in northwest Louisiana; our Marcellus Shale region primarily in Pennsylvania and West Virginia; our Niobrara Shale region in eastern Wyoming; our Utica Shale region in eastern Ohio; and our 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 through long-term, fixed-fee gas gathering, treating and compression contracts and increasingly through 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:
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opportunity to connect drilling pads and wells of the counterparties to these agreements within our acreage dedications to our gathering systems in each applicable region;
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fee redetermination or cost of service mechanisms in the majority of our regions that are designed to support a return on invested capital and allow our gathering rates to be adjusted, subject to specified caps in certain cases, to account for variability in volume, capital expenditures, compression and other expenses;
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minimum volume commitments in our Barnett Shale and Haynesville Shale regions which mitigate throughput volume variability; and
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price escalators in certain of our operating regions, which annually increase our gathering rates.
Information About Us
Our principal executive offices are located at 525 Central Park Drive, Oklahoma City, Oklahoma 73105, and our telephone number is (405) 935-7800. 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 and conflicts 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.
Acquisitions
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, the Partnership now owns certain midstream assets in the Eagle Ford, Utica and Niobrara regions. The CMO Acquisition also extended our 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 acquired CMO assets 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 closing of the Williams Acquisition, the GIP II Entities and Williams together own and control our general partner and the GIP I Entities no longer have any ownership interest in the Partnership or our general partner.
Our Marcellus Acquisition
On December 29, 2011, we acquired from CMD all of the issued and outstanding common units of 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 the acquisition of Appalachia Midstream, we operate 100 percent of and own an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 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 commitment in 2012.
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 2012 and the two-day period from closing of the acquisition on December 29, 2011, through December 31, 2011 and are included in income from unconsolidated affiliates.
Our Haynesville Springridge Acquisition
On December 21, 2010, we acquired the Springridge gathering system and related facilities located in Caddo and De Soto Parishes, Louisiana from CMD for $500.0 million. In connection with the acquisition, we entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake that includes a significant acreage dedication, an annual fee redetermination mechanism and a three-year minimum volume commitment.
The results of operations presented and discussed in this annual report include results of operations from the Springridge gathering system for the full year of operations in 2012 and 2011, as well as the eleven-day period from closing of the acquisition on December 21, 2010, through December 31, 2010.
Our Assets and Areas of Operation
The following table summarizes average daily throughput and assets by region as of and for the year ended December 31, 2012:
(1) Excludes CMO assets acquired on December 20, 2012 due to immaterial contribution to 2012 results.
(2) Throughput in the Marcellus Shale region represents the net throughput allocated to the Partnership’s interest.
Barnett Shale Region
General. Our gathering systems in our Barnett Shale region are primarily located in Tarrant, Johnson and Dallas counties in Texas in the Core and Tier 1 areas of the Barnett Shale and consist of 25 interconnected gathering systems and 850 miles of pipeline. The Core and Tier 1 areas are characterized by thicker natural gas bearing geological zones, which results in higher initial production rates. Typically, gas produced in Core and Tier 1 areas is characterized as “lean” and needs little to no treatment to remove contaminants.
Our assets in the Barnett region have been designed and developed to accommodate their urban setting in and around the greater Dallas/Fort Worth, Texas metropolitan area. Average throughput on our Barnett Shale gathering system for the year ended December 31, 2012, was 1.195 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 102 compressor units providing a combined 161,275 horsepower of compression.
Delivery Points. Our Barnett Shale gathering system is connected to the following downstream transportation pipelines:
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Atmos Pipeline Texas-natural gas delivered into this pipeline system serves the greater Dallas/Fort Worth metropolitan area and south, east and west Texas markets at the Katy, Carthage and Waha hubs;
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Energy Transfer Pipeline Texas-natural gas delivered into this pipeline system serves the greater Dallas/Fort Worth metropolitan area and southeastern and northeastern U.S. markets supplied by the Midcontinent Express Pipeline, Centerpoint CP Expansion Pipeline and Gulf South 42-inch Expansion Pipeline; and
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Enterprise Texas Pipeline-natural gas delivered into this pipeline system serves the greater Dallas/Fort Worth metropolitan area and southeastern and northeastern U.S. markets supplied by the Gulf Crossing Pipeline.
Eagle Ford Shale Region
General. We acquired gathering systems in the Eagle Ford Shale as part of the CMO Acquisition. Our gathering systems in our Eagle Ford Shale region are primarily located in Dimmit, La Salle, Frio, Zavala, McMullen and Webb counties in Texas and consist of 10 gathering systems and 618 miles of pipeline. Gas in the Eagle Ford formation is typically wet and requires treatment and processing to remove NGLs prior to delivery into the pipeline grid. Gas produced in the Eagle Ford formation typically needs to be treated to remove small to large amounts of carbon dioxide and hydrogen sulfide.
Gross throughput for these assets at December 31, 2012, was 0.169 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 28 compressor stations providing a combined 38,007 horsepower of compression.
Delivery points. Our Eagle Ford gathering systems are connected to the following downstream transportation pipelines.
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Enterprise-processes gas at Yoakum or other Enterprise plants and transports residue to Wharton residue header with connections to numerous interstate pipelines;
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Camino Real-transports to Enterprise Products or Eagle Ford Gathering;
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West Texas Gas-distributes gas to various industrial customers in the local region of South Texas;
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Regency Gas Service-treats sour gas and redelivers to Enterprise Products;
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Eagle Ford Gathering-processes gas at Houston Central plant and delivers residue to header with connections to numerous interstate pipelines; and
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Enerfin-transports to Enterprise Products
Haynesville Shale Region
Springridge Gathering System
General. Our Springridge gas gathering system in the Haynesville Shale region is primarily located in Caddo and DeSoto Parishes, Louisiana, in one of the core areas of the Haynesville Shale and consists of 263 miles of pipeline. The core areas are characterized by thicker natural gas bearing geological zones, which results in higher initial production rates. Haynesville Shale gas production is characterized as “lean” and typically needs to be treated to remove small amounts of carbon dioxide and hydrogen sulfide.
A portion of our assets in the Springridge gathering system has 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, 2012, was 0.359 Bcf per day. We connect our gathering system to receipt points that are at central receipt points into which production from multiple wells is gathered. Our Springridge gathering system has pipeline diameters ranging from four-inch well connection lines to a 24-inch major trunk line and is connected to 11 compressor units providing a combined 23,745 horsepower of compression.
Delivery Points. Our Springridge gathering system is connected to the following downstream transportation pipelines:
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Centerpoint Energy Gas Transmission-natural gas delivered into this 42-inch diameter pipeline can be received at the Carthage, Texas, and Perryville, Louisiana hubs, and is connected to numerous interstate pipelines;
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ETC Tiger Pipeline-natural gas delivered into this 42-inch diameter pipeline can also be received at the Carthage and Perryville hubs. ETC Tiger Pipeline provides deliveries to seven interstate pipelines and one intrastate pipeline for ultimate delivery to the Midwest and Northeast; and
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Texas Gas Transmission Pipeline-natural gas delivered into this pipeline can move to on-system markets in the Midwest and to off-system markets in the Northeast via interconnections with third-party pipelines or it can be received at the Carthage hub in East Texas.
Mansfield Gathering System
General. We acquired the Mansfield gathering system in the Haynesville Shale region as part of the CMO Acquisition. Our Mansfield gas 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, 2012, consist of 304 miles of pipeline. The core areas served by this system are characterized by thicker natural gas bearing geological zones, which results in higher initial production rates. Haynesville Shale gas production is characterized as “lean” and typically needs to be treated to remove small amounts of carbon dioxide and hydrogen sulfide.
Average throughput on our Mansfield gathering system at the end of 2012 was 0.720 Bcf per day. We connect our gathering system to receipt points that are at central receipt points into which production from multiple wells is gathered and treated. Our Mansfield gathering system has pipeline diameters ranging from six-inch well connection lines to a 24-inch major trunk line.
Delivery Points. Our Mansfield gathering system is connected to the following downstream transportation pipelines:
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Centerpoint Energy Gas Transmission-natural gas delivered into this 42-inch diameter pipeline can be received at the Carthage, Texas, and Perryville, Louisiana hubs, and is connected to numerous interstate pipelines;
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ETC Tiger Pipeline-natural gas delivered into this 42-inch diameter pipeline can also be received at the Carthage and Perryville hubs. ETC Tiger Pipeline provides deliveries to seven interstate pipelines and one intrastate pipeline for ultimate delivery to the Midwest and Northeast;
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Enterprise Accadian Pipeline-natural gas delivered into this pipeline can move to on-system markets in the Midwest and to off-system markets in the Northeast via interconnections with third-party pipelines; and
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Gulf South Pipeline-natural gas delivered into this pipeline can move to on-system markets in the Midwest and to off-system markets in the Northeast via interconnections with third-party pipelines.
Marcellus Shale Region
General. Through Appalachia Midstream, we operate 100 percent of and own an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 549 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. As part of the CMO Acquisition, we acquired additional assets in the Marcellus Shale region consisting of 618 miles of pipeline. We operate these smaller systems in northeast and central West Virginia, southeast Pennsylvania, northwest Maryland, north central Virginia, and south central New York. Marcellus Shale gas production can be characterized as “lean” dry gas or wet gas depending on its location. In general, the gas in the northern Marcellus Shale is lean and typically requires little to no treatment to remove contaminants. Southern Marcellus Shale gas is wet and typically requires treatment and processing to remove NGLs prior to delivery into the pipeline grid. Gross throughput for Appalachia Midstream assets for the year ended December 31, 2012 was just over 1.8 Bcf per day (approximately 0.701 Bcf per day net to us). Gross throughput for the additional acquired assets in the Marcellus Shale region at December 31, 2012, was just over 0.026 Bcf per day. 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:
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Caiman Energy-rich natural gas is delivered into a 16-inch pipeline and delivered to the Caiman Energy Fort Beeler processing plant where the liquids are extracted from the rich gas stream. The natural gas is then delivered into the TETCo interstate pipeline for ultimate delivery to the Northeast region of the U.S.;
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Central New York Oil & Gas-natural gas delivered into this 30-inch diameter pipeline (South Lateral of Stagecoach Storage) can be delivered to Stagecoach Storage, Millennium Pipeline, or Tennessee Gas Pipeline’s Line 300. Together with Inergy’s proposed Marc I Pipeline, gas delivered into this pipeline will be able to be transported bi-directionally approximately 75 miles between the Millennium Pipeline and Transco’s Leidy Line and all points between;
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Columbia Gas Transmission-lean natural gas is delivered into two 36-inch interstate pipelines for ultimate delivery to the Mid-Atlantic and Northeast regions of the U.S.;
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MarkWest-rich natural gas is delivered into a MarkWest pipeline for delivery to the MarkWest Houston processing plant where the liquids are extracted from the rich gas stream. The natural gas is then delivered into the TCO and TETCo interstate pipelines for ultimate delivery to the Mid-Atlantic and Northeast regions of the U.S. The extracted liquid is then delivered to the MarkWest fractionation plant in Houston, Pennsylvania;
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NiSource Midstream-rich natural gas is delivered into a 20-inch diameter pipeline and delivered to the MarkWest Majorsville processing plant where the liquids are extracted from the rich gas stream. The natural gas is then delivered into the TCO and TETCo interstate pipelines for ultimate delivery to the Mid-Atlantic and Northeast regions of the U.S. The extracted liquid is then delivered to the MarkWest fractionation plant in Houston, Pennsylvania;
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PVR-natural gas is delivered into the 24-inch diameter Wyoming pipeline and the Hirkey Compressor Station. The natural gas is then delivered into the Transco interstate pipeline with deliveries into major metropolitan areas in New York, New Jersey and Pennsylvania; and
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Tennessee Gas Pipeline-natural gas delivered into this looped 30-inch diameter pipeline (TGP Line 300) at three different locations can be received in the Northeast at points along the 300 Line path, various interconnections with other pipelines in northern New Jersey, as well as an existing delivery point in White Plains, New York.
Niobrara Shale Region
General. As part of the CMO Acquisition, we acquired a 50 percent operating interest in a joint venture that owns two 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 gathering systems and 79 miles of pipeline. This area is characterized by thicker natural gas bearing geological zones, which results in higher initial production rates. Typically, gas produced is characterized as wet and requires treatment and processing to remove NGLs prior to delivery to the pipeline grid.
Average throughput in our Niobrara Shale region at the end of 2012 was 0.013 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 systems have pipeline diameters ranging from four-inch well connection lines to 16-inch major trunk lines and are connected to five compressor units providing a combined 4,625 horsepower of compression.
Delivery Points. Our Niobrara gathering systems are connected to the following downstream transportation pipelines:
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Tallgrass/Douglas Pipeline-natural gas delivered into this pipeline is sent to the Tallgrass processing facility; after processing, natural gas is delivered to Cheyenne Hub, Rockies Express Pipeline, or Trailblazer Pipeline via Tallgrass Interstate Gas Transmission. NGLs go to ConocoPhillips fractionation in Borger, Texas; and
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North Finn/DCP Inlet Pipeline-this is a delivery point with only interruptible takeaway capacity that ultimately flows to the nearby Tallgrass processing facility for further processing.
Utica Shale Region
General. As part of the CMO Acquisition, we acquired a 66 percent operating interest in a joint venture that owns five gas gathering systems, a 100 percent ownership interest in four gas gathering systems and a 49 percent non-operating interest in a joint venture that is currently constructing four processing trains, a fractionation facility, NGL storage capacity and other ancillary assets. Our gathering systems in the Utica Shale region are primarily located in northeast Ohio and consist of 67 miles of pipeline.
Delivery Points. Our Utica gathering systems are connected to the following downstream transportation pipelines:
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Dominion East Ohio (Blue Racer)-currently tied into TPL 7, and 18-inch wet gas gathering pipeline with access to Dominion Transmission, Inc. Hastings extraction facility and the anticipated Natrium extraction facility. Residue pipelines from both facilities have access to Dominion Transmission and other major pipelines; and
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Dominion Transmission, Inc.-currently tied into TL 400 which provides access to major Northeast markets.
Mid-Continent Region
Our Mid-Continent gathering systems extend across portions of Oklahoma, Texas, Arkansas and Kansas. Included in our Mid-Continent region are three treating facilities located in Beckham and Grady Counties, Oklahoma, and Reeves County, Texas, that are designed to remove contaminants from the natural gas stream.
Anadarko Basin and Northwest Oklahoma
General. Our assets within the Anadarko Basin and Northwest Oklahoma are located in northwestern Oklahoma and the northeastern portion of the Texas Panhandle and consist of approximately 1,578 miles of pipeline. Our Anadarko Basin and Northwest Oklahoma region gathering systems had an average throughput for the year ended December 31, 2012 of 0.457 Bcf per day. These systems are connected to 70 compressor units providing a combined 71,230 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, we operate an amine treater with sulfur removal capabilities at our Mayfield facility in Beckham County, Oklahoma. Our Mayfield gathering and treating system primarily gathers Deep Springer natural gas production and treats the natural gas to remove carbon dioxide and hydrogen sulfide to meet the quality specifications of downstream transportation pipelines.
Delivery Points. Our Anadarko Basin and Northwest Oklahoma systems are connected to a significant majority of the major transportation pipelines transporting natural gas out of the region, including pipelines owned by Enbridge and Atlas Pipelines, as well as local market pipelines such as those owned by Enogex. These pipelines provide access to Midwest and northeastern U.S. markets as well as intrastate markets.
Permian Basin
General. Our Permian Basin assets are located in west Texas and consist of approximately 358 miles of pipeline across the Permian and Delaware basins. Average throughput on our gathering systems for the year ended December 31, 2012, was 0.076 Bcf per day. The systems have pipeline diameters ranging from four inches to 16 inches and are connected to 17 compressor units providing a combined 14,400 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.
Other Mid-Continent Regions
Our other Mid-Continent region assets consist of systems in the Ardmore Basin in Oklahoma, the Arkoma Basin in eastern Oklahoma and western Arkansas and the East Texas and Gulf Coast regions of Texas. The other Mid-Continent assets include approximately 648 miles of pipeline. These gathering systems are generally localized systems gathering specific production for re-delivery into established pipeline markets. Average throughput on these gathering systems for the year ended December 31, 2012 was 0.031 Bcf per day. The systems have pipeline diameters ranging from four inches to 24 inches and are connected to 36 compressor units providing a combined 17,826 horsepower of compression.
General Trends
We continue to see a trend by our producer customers of shifting drilling activity from dry gas shale plays, such as our Barnett Shale and Haynesville Shale regions to liquids-rich plays such as our Eagle Ford, Marcellus, Niobrara, Utica and Mid-Continent regions. We believe this trend is likely to continue for the foreseeable future. Any decrease in production in the Barnett Shale and Haynesville Shale will be mitigated as our contractual protections of minimum volume commitment and rate redetermination work to support our financial performance in these regions.
The CMO Acquisition and the resulting expansion of our services into the Eagle Ford, Niobrara and Utica Shale regions expand our opportunity to serve producer customers in liquids-rich areas. The CMO Acquisition will also allow us to enter the business line of processing gas to produce NGLs. We expect to begin earning more significant fees from processing natural gas in late 2013.
The recent natural gas price environment has resulted in lower drilling activity generally in our dry gas shale plays, resulting in fewer new well connections and, in some cases, temporary curtailments of production in certain of the areas in which we operate. A continued low gas price environment may result in further reductions in drilling activity or temporary curtailments of production. We have no control over this activity. In addition, further decline in commodity prices could affect production rates and the level of capital invested by 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.
Competition
Given that substantially all of the natural gas gathered and transported through our systems 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 their natural gas produced from existing and future wells located on lands within our acreage dedication in the Barnett Shale region, and Chesapeake has made a similar dedication in our Haynesville Shale, Eagle Ford Shale, Niobrara Shale and certain of our Utica Shale regions. 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 Chesapeake’s production drilled outside of our acreage dedication and in attracting third-party volumes to our systems. Additionally, to the extent we make acquisitions from third parties we could face incremental competition. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies. We believe that our competitors in each region include:
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Barnett Shale-Energy Transfer Partners, Crosstex Energy, Crestwood Midstream Partners, Freedom Pipeline, Peregrine Pipeline, XTO Energy, EOG Resources, DFW Mid-Stream and Enbridge Energy Partners;
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Eagle Ford Shale-DCP Midstream, Energy Transfer Partners, Enterprise Products Partners Inc., Regency Energy Partners, Texstar Midstream Operating, West Texas Gas Inc.;
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Haynesville Shale-TGGT Holdings, Enterprise Products Partners, Kinderhawk Field Services, CenterPoint Field Services, and Energy Transfer Partners;
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Marcellus Shale-Williams Partners, Penn Virginia Resource Partners, Caiman Energy, MarkWest Energy Partners and Talisman Energy;
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Niobrara Shale-DCP Midstream, Kinder Morgan;
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Utica Shale-Dominion Transmission (Blue Racer), MarkWest; and
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Mid-Continent-Enogex, Atlas Pipeline Partners, Enbridge and DCP Midstream.
Employees
At every level of our operations, our employees are critical to our success and committed to operational excellence. Our senior management team has impressive experience building, acquiring and managing midstream and other assets. Their focus is on optimizing our business and expanding operations. On an operations level, our supervisory and field personnel are empowered with the training, tools and confidence required to succeed in their jobs.
The officers of our general partner manage our operations and activities. As of December 31, 2012, our general partner employed approximately 1,255 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.
Safety and Maintenance
We are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the Department of Transportation (“DOT”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002 (“PSIA”) which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, and reauthorized through 2015 by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“PSRC”). The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas 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.
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 gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.
Regulation of Operations
Natural gas gathering and intrastate transportation facilities are exempt from the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act (“NGA”). Although FERC has not made any formal determinations with respect to any of our facilities, we believe that our natural gas pipelines and related facilities are engaged in exempt gathering and intrastate transportation and, therefore, are not subject to FERC jurisdiction.
FERC regulation affects our gathering and compression business generally. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, capacity release and market transparency and market center promotion, directly and indirectly affect our gathering business. In addition, the distinction between FERC-regulated transmission facilities and federally unregulated gathering and intrastate transportation facilities is a fact-based determination made by FERC on a case by case basis; this distinction has also been the subject of regular litigation and change. The classification and regulation of our gathering and intrastate transportation facilities are subject to change based on future determinations by FERC, the courts or Congress.
Our natural gas gathering operations are subject to ratable take and common purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination.
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 is authorized to impose civil penalties of up to $1.0 million per day per violation and grant other relief, such a 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 $1,000,000 or triple the monetary gain for violations of its anti-market manipulation regulations.
Environmental Matters
General
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:
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requiring the installation of pollution-control equipment;
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restricting the way we can handle or dispose of our wastes;
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limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;
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requiring investigatory and remedial actions to limit pollution conditions caused by our operations or attributable to former operations; and
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prohibiting the operation of facilities deemed to be in non-compliance with permits issued pursuant to such environmental laws and regulations.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial obligations, and the issuance of orders enjoining future operations or imposing additional compliance requirements. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.
Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.
Hazardous Substances and Waste
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes, and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” or “Superfund law”) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include current and prior owners or operators of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA 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.
Air Emissions
Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. For example, the Texas Commission on Environmental Quality (“TCEQ”) has 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. 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.
Water Discharges
The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the U.S. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state 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
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. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of natural gas that our customers produce, and could thereby adversely affect our revenues and results of operations. For further discussion, see “Risk Factors-Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.”
Endangered Species
The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states. 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.
Global Warming and Climate Change
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules. With regard to the monitoring and reporting of greenhouse gases, on November 30, 2010, the EPA published a final rule expanding its existing greenhouse gas emissions reporting rule published in October 2009 to include natural gas processing, transmission, storage and distribution activities. 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.
Title to Properties and Rights-of-Way
Our real property falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our pipelines and facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our pipelines and facilities are located are held by us pursuant to surface leases, easements, rights-of-way, permits or licenses between us and the fee owner of the lands. We, or our predecessor, have leased land rights (as provided above) to much of these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.
Legal Proceedings
We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please read “-Regulation of Operations” and “-Environmental Matters.”
ITEM 1A.
ITEM 1A. Risk Factors
Risks Related to Our Business
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, 2012, Chesapeake accounted for approximately 75 percent of the fees on our gathering systems. On a pro forma basis for the year ended December 31, 2012, after giving effect to the CMO Acquisition, Chesapeake would have accounted for approximately 80 percent of the fees on our gathering systems.
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:
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the volatility of natural gas, NGL and oil prices, which could have a negative effect on the value of its oil and natural gas properties, its drilling programs or its ability to finance its operations;
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the availability of capital on an economic basis to fund its exploration and development activities;
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its ability to replace reserves, sustain production and begin production on certain leases that may otherwise expire;
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uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production;
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its drilling and operating risks, including potential environmental liabilities;
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transportation capacity constraints and interruptions;
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adverse effects of governmental and environmental regulation; and
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losses from pending or future litigation.
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 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 liquids-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, Haynesville Shale and Marcellus Shale regions. A reduction in the natural gas volumes supplied by Chesapeake, Total or other producers could result in reduced throughput on our systems and adversely impact our ability to grow our operations and increase cash distributions to our unitholders.
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.
We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution on each of our common units, subordinated units, Class C units and the two percent general partner interest outstanding. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
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the volume of natural gas we gather, treat, compress and process;
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the level of production of, the demand for, and, indirectly, the price of natural gas, NGLs and oil;
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the level of our operating and general and administrative costs;
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regulatory action affecting the supply of or demand for natural gas, NGLs and oil, our operations, the rates we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and
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prevailing economic conditions.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
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the level of capital expenditures we make, including capital expenditures for connecting new operated drilling pads or new operated wells of producers in our acreage dedications as required by our gas gathering agreements;
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the cost of acquisitions, if any;
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our debt service requirements and other liabilities;
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fluctuations in our working capital needs;
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our ability to borrow funds and access capital markets;
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restrictions contained in our debt agreements;
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the amount of cash reserves established by our general partner; and
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other business risks affecting our cash levels.
The amount of cash available for distribution will also be reduced by the amount we reimburse Chesapeake for its provision of certain general and administrative services and any additional services we may request from Chesapeake, each pursuant to our services agreement with Chesapeake. In addition, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. Under our partnership agreement, our general partner determines in good faith the amount of these expenses.
Chesapeake’s level of indebtedness could adversely affect our ability to grow our business, our ability to make cash distributions to our unitholders and our credit ratings and profile.
Chesapeake must devote a portion of its cash flows from operating activities to service its indebtedness, and such cash flows are therefore not available for further development activities, which 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. Such a default could occur after the conversion of the subordinated units as a result of our general partner’s ability, for purposes of testing whether the subordination period has ended, to include as “earned” in a particular quarter its prorated estimates of shortfall payments to be earned by the end of the then current calendar year under the minimum volume commitments contained in certain of our gas gathering agreements. 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, the production from which may be less than we expect and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering systems, we must obtain new sources of natural gas 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 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, NGL 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 natural gas, NGL or oil prices could have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our gathering, 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 in unconventional resource plays, as the basins in those plays generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Accordingly, volumes on our systems serving unconventional resource plays may need to be replaced at a faster rate to maintain or grow the current volumes than may be the case in other regions of production. In addition to significant capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to estimate higher maintenance capital expenditures over time, which will reduce our cash available for distribution from operating surplus.
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 systems. Additionally, if a gas gathering agreement is terminated as to only a particular Barnett Shale gathering system, the minimum volume commitment may be reduced for gas volumes that would have been gathered on the terminated gathering system. After the termination of a gas gathering 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 agreements may not operate as intended, including the volumetric-based cap associated with fuel and lost and unaccounted for gas, which could subject us to direct commodity price risk and adversely affect our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders.
Our gas gathering agreements contain provisions relating to, among other items, periodic fee redeterminations, 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 agreements might not operate as intended.
The fee redetermination, cost of service mechanism and other provisions of our gas gathering agreements are intended to support the stability of our cash flows and were designed with the goal of supporting a return on our invested capital, which is not equivalent to ensuring that our business will generate a particular amount of cash flow. Our fee redetermination and cost of service provisions do not take into consideration all expenses and other variables, including certain operating expenditures, that would affect our return on invested capital. In addition, our gathering rates may be adjusted upward or downward following a fee redetermination or cost of service calculation, subject to specified caps in certain cases. The change in law provisions contained in our gas gathering agreements are designed to provide for our reimbursement by customers of certain taxes, fees, assessments and other charges that we may incur as a result of changes in law. These change in law provisions may not cover all legal or regulatory changes that could have an adverse economic impact on our operations. We have also agreed with our customers on caps on fuel and lost and unaccounted for gas on certain of our systems. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel and lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.
If these or other provisions of our gas gathering agreements do not operate as intended, our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders could be adversely affected.
We do not obtain independent evaluations of natural gas and NGL reserves connected to our gathering systems; therefore, in the future, volumes of natural gas and NGLs on our systems could be less than we currently anticipate.
We do not obtain independent evaluations of natural gas and NGL reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. Notwithstanding the contractual protections in certain of our gas gathering agreements, including minimum volume commitments in our Barnett Shale region, and Haynesville Shale region, and fee redetermination and cost of service provisions, if the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas 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 applicable 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 will be subject to review and change by our conflicts committee at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing and make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the anticipated level and could be required to reduce our distributions.
We conduct certain operations through joint ventures that may limit our operational flexibility.
Our operations in the Marcellus Shale (through Appalachia Midstream), Niobrara Shale, Utica Shale and certain of our Mid-Continent regions 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:
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we have limited ability to influence or control certain day to day activities affecting the operations;
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we cannot control the amount of capital expenditures that we are required to fund with respect to these operations;
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we are dependent on third parties to fund their required share of capital expenditures;
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we may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets; and
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we may be forced to offer rights of participation to other joint venture participants in the area of mutual interest.
In addition, our joint venture participants may have obligations that are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture and to pay their share of capital and other costs of the joint venture. The performance and ability of the third parties to satisfy their obligations under joint venture arrangements is outside our control. If these parties do not satisfy their obligations under these arrangements, our business may be adversely affected. Our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives, and disputes between us and our joint venture partners may result in delays, litigation or operational impasses. The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to conduct our Marcellus, Niobrara and Utica 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:
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performance from the acquired assets and businesses that is below the forecasts we used in evaluating the acquisition;
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an inability to secure adequate customer commitments to use the acquired systems or facilities;
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an inability to successfully integrate the assets or businesses we acquire;
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the assumption of unknown liabilities;
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the diversion of management’s and employees’ attention from other business concerns;
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an increase in our indebtedness and working capital requirements; and
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significant changes in our capitalization and results of operations.
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 may fail to successfully integrate the assets acquired in the CMO Acquisition with our existing business in a timely manner, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders, or fail to realize all of the expected benefits of the acquisition, which could negatively impact our future results of operations.
Integration of the assets acquired in the CMO Acquisition with our existing business will be a complex, time-consuming and costly process, particularly given that the acquired assets significantly increased our size and diversified the geographic areas in which we operate. A failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
If any of the risks described in the risk factor immediately above or unanticipated liabilities or costs were to materialize with respect to the CMO Acquisition, or if the acquired assets were to perform at levels below the forecasts we used to evaluate them, then the anticipated benefits from the acquisition may not be fully realized, if at all, and our future results of operations could be negatively impacted.
The CMO Acquisition could expose us to potential significant liabilities.
In connection with the CMO Acquisition, we assumed certain liabilities, including unknown and contingent liabilities, associated with the acquired assets, including certain environmental liabilities, employee benefit plan liabilities and obligations arising in connection with or relating to the business, purchased assets, facilities or real property of CMO’s business. Although CMD has agreed to indemnify us on a limited basis against some of these liabilities, a significant portion of these indemnification obligations will expire within specified time periods after the date the CMO Acquisition was completed, and these obligations are generally subject to limits. CMD’s indemnity obligations are generally capped at 20 percent of the total purchase price paid by us in the CMO Acquisition. We may not be able to collect on such indemnification because of disputes with CMD or the inability of it (or Chesapeake, as guarantor of CMD’s obligations) to pay at the time such indemnification is sought. Moreover, there is a risk that we could ultimately be liable for unknown obligations related to the CMO Acquisition, which could materially adversely affect our financial condition, results of operations or cash flows. Any loss we incur in connection with these liabilities that is not fully indemnified by CMD could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Our exposure to direct commodity price risk may increase in the future.
We currently generate substantially all of our revenues pursuant to fixed-fee contracts under which we are paid based on the volumes of natural gas that we gather, 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, financial condition and ability to make cash distributions to our unitholders.
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:
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damage to pipelines and facilities, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, explosions and other natural disasters and acts of terrorism;
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inadvertent damage from construction, farm and utility equipment;
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leaks of natural gas and other hydrocarbons or losses of natural gas and other hydrocarbons as a result of the malfunction of equipment or facilities; and
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other hazards.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. In addition, 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 flows.
Restrictions in our revolving credit facility and indentures could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our units.
We are dependent upon the earnings and cash flow generated by our operations in order to meet our debt service obligations and to make cash distributions to our unitholders. The operating and financial restrictions and covenants in our revolving credit facility, our indentures and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders. For example, our revolving credit facility and indentures restrict our ability to, among other things:
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incur additional debt or issue guarantees;
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incur or permit certain liens to exist;
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make certain investments, acquisitions or other restricted payments;
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dispose of assets;
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engage in certain types of transactions with affiliates;
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merge, consolidate or transfer all or substantially all of our assets; and
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prepay certain indebtedness.
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:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including required drilling pad connections and well connections pursuant to certain of our gas gathering agreements as well as acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;
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our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
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we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
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our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to affect any of these actions on satisfactory terms or at all.
The amount of cash we have available for distribution to holders of our common, subordinated units, and Class C 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. In addition, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the process of drafting guidance documents related to this assertion of regulatory authority. In addition, some states and municipalities have adopted, and other states and municipalities are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress to provide for such regulation. We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through our gathering systems which would materially adversely affect our revenues and results of operations.
We may incur significant costs and liabilities in complying with, or as a result of a failure to comply with, new or existing environmental laws and regulations, and changes in environmental laws or regulations could adversely impact our customers’ production and operations, which could have a material adverse effect on our results of operations and cash flows.
Our natural gas gathering, treating, 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. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. With regard to the monitoring and reporting of greenhouse gases, on November 30, 2010, the EPA published a final rule expanding its existing greenhouse gas emissions reporting rule published in October 2009 to include onshore oil and natural gas processing, transmission, storage, and distribution activities. 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.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the natural gas we gather, treat and transport. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.
If our assets became subject to regulation by FERC or regulations of state and local agencies were to change, our financial condition, results of operations and cash flows could be materially and adversely affected.
Natural gas gathering and intrastate transportation facilities are exempt from the jurisdiction of FERC under the NGA. Although FERC has not made any formal determinations respecting any of our facilities, we believe that our natural gas pipelines and related facilities are engaged in exempt gathering and intrastate transportation and, therefore, are not subject to FERC jurisdiction. If FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of services provided by such facility would be subject to regulation by FERC. Such regulation could decrease revenues, increase operating costs, and depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or the Natural Gas Policy Act, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by FERC.
Moreover, FERC regulation affects our gathering and compression business generally. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, capacity release and market transparency and market center promotion, directly and indirectly affect our gathering business. In addition, the distinction between FERC-regulated transmission facilities and federally unregulated gathering and intrastate transportation facilities is a fact-based determination made by FERC on a case by case basis; this distinction has also been the subject of regular litigation and change. The classification and regulation of our gathering and intrastate transportation facilities are subject to change based on future determinations by FERC, the courts or Congress.
State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. We cannot predict what new or different regulations federal and state regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Such regulations may have a material adverse effect on our financial condition, results of operations and cash flows.
If our services agreement with Chesapeake is terminated, or if Chesapeake fails to provide us with adequate services, we will have to obtain those services internally or through third-party arrangements.
We depend on Chesapeake to provide us certain general and administrative services and any additional services we may request pursuant to our services agreement. The term of the provision of general and administrative services by Chesapeake under the services agreement will continue until December 31, 2013, subject to certain conditions and limitations. Though Chesapeake will agree to perform such services using no less than a reasonable level of care in accordance with industry standards, if Chesapeake fails to provide us adequate services, or if the services agreement is terminated for any reason, we will have to obtain these services internally or through third-party arrangements which may result in increased costs to us.
If we fail to maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.
Prior to our IPO in July 2010, we were not required to file reports with the SEC. Upon the completion of the offering, we became subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We prepare our consolidated financial statements in accordance with generally accepted accounting principles (“GAAP”), but prior to December 31, 2011, our internal accounting controls were not required to meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. We were required to comply with Section 404 for our fiscal year ended December 31, 2011. Any failure to maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our or our independent registered public accounting firm’s conclusions about the effectiveness of our internal controls. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.
Risks Inherent in an Investment in Us
The GIP II Entities and Williams, through their joint ownership of 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:
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Neither our partnership agreement nor any other agreement requires the GIP II Entities, Williams or Access Midstream Ventures to pursue a business strategy that favors us. For example, Williams is not a party to any agreement that prohibits it from competing against us in our gas gathering and processing operations and for gathering, processing and acquisition opportunities. It is possible that Williams could block us from pursuing opportunities in which Williams has a competitive interest.
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Our general partner is allowed to take into account the interests of parties other than us, such as the GIP II Entities, Williams or Access Midstream Ventures, in resolving conflicts of interest.
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Our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.
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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
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Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.
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Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.
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Our general partner determines which costs incurred by it are reimbursable by us.
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Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.
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Our partnership agreement permits us to classify up to $120 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.
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Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
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Our general partner intends to limit its liability regarding our contractual and other obligations.
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Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80 percent of the common units.
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Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.
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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
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Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.
Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.
Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
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how to allocate business opportunities among us and its affiliates;
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whether to exercise its limited call right;
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how to exercise its voting rights with respect to the units it owns;
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whether to elect to reset target distribution levels; and
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whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above.
Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:
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provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
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provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in the best interest of our partnership;
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provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:
(a) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;
(b) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
(c) on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
(d) fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of
interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.
Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0 percent) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will equal the number of common units which would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner’s general partner interest in us (currently two percent) will be maintained at the percentage that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash 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 nine members, three 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 three independent directors. If the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Even if holders of our common units are dissatisfied, they cannot remove our general partner currently without the GIP II Entities and Williams’ consent.
Our unitholders are currently unable to remove our general partner because our general partner and its affiliates own sufficient units to prevent its removal. The vote of the holders of at least 66 2/3 percent of all outstanding common, subordinated, Class B and Class C units, voting together as a single class, is required to remove our general partner. As of February 12, 2013, the GIP II Entities and Williams together own an aggregate of 66.4 percent of our outstanding common, subordinated, Class B and Class C units. Also, if our general partner is removed without cause during the subordination period and no units held by the holders of the subordinated units or their affiliates are voted in favor of that removal, all subordinated units held by our general partner and its affiliates will automatically be converted into common units. If no units held by any holder of subordinated units or its affiliates are voted in favor of that removal, all subordinated units will convert automatically into common units and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely
affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.
Our partnership agreement restricts the voting rights of unitholders owning 20 percent or more of our common units.
Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner, its affiliates, their direct transferees and their indirect transferees approved by our general partner (which approval may be granted in its sole discretion) and persons who acquired such units with the prior approval of our general partner, cannot vote on any matter.
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 jointly owned and controlled indirectly 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 12, 2013, 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 three 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:
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our existing unitholders’ proportionate ownership interest in us will decrease;
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the amount of cash available for distribution on each unit may decrease;
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because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit may be diminished; and
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the market price of the common units may decline.
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 12, 2013, the GIP II Entities and Williams together hold an aggregate of approximately 33.7 million common units, approximately 69.1 million subordinated units, approximately 11.9 million Class B units and approximately 11.2 million Class C units. All of the subordinated units will convert into common units at the end of the subordination periods and may convert earlier under certain circumstances. After the record date for the distribution on common units for the fiscal quarters ending December 31, 2013 and December 31, 2014, each Class
C unit and Class B unit, respectively, will become convertible into a common unit on a one-for-one basis at the option of 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 12, 2013, the GIP II Entities and Williams together own approximately 34.6 percent (exclusive of subordinated, Class B and Class C units) of our outstanding common units. At the end of the various subordination and conversion periods, assuming no additional issuances of common units (other than upon the conversion of the subordinated, Class B and Class C 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 66.4 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:
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we were conducting business in a state but had not complied with that particular state’s partnership statute; or
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your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (“Delaware Act”) we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
Tax Risks to Common Unitholders
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, our cash available for distribution to you would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us. Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35 percent, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to you.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. 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. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest 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 cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the 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 recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.
As a result of investing in our common units, you may become subject to state, local and non-U.S. taxes and return filing requirements in jurisdictions where we operate or own or acquire property.
In addition to federal income taxes, you will likely be subject to other taxes, including non-U.S., state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file non-U.S., state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We own assets and conduct business in Arkansas, Kansas, Louisiana, Maryland, New York, Ohio, Oklahoma, Pennsylvania, Texas, Virginia, 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.
ITEM 1B.
ITEM 1B. Unresolved Staff Comments
None.
ITEM 2.
ITEM 2. Properties
Substantially all of our pipelines, which are located in Arkansas, Kansas, Louisiana, Maryland, New York, Ohio, Oklahoma, Pennsylvania, Texas, Virginia, 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 with Chesapeake 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.”
ITEM 3.
ITEM 3. Legal Proceedings
We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business.
ITEM 4.
ITEM 4. Mine Safety Disclosures
Not applicable.
Part II
ITEM 5.
ITEM 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common units are listed on the NYSE under the symbol “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 during each quarter over the last two fiscal years.
Fourth quarter 2012 distributions were payable on Class B and Class C units in addition to common and subordinated units.
As of February 12, 2013, there were approximately 28 unitholders of record of the Partnership’s common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. We have also issued 69,076,122 subordinated units, 11,858,050 Class B units, 11,199,268 Class C units, and ownership interests in the general partner, for which there is no established public trading market. All of the subordinated units, Class B and Class C units and general partner interests are held by affiliates of our general partner. Our general partner and its affiliates receive quarterly distributions on the subordinated units and Class C units only after sufficient funds have been paid to the common units. Class B units are entitled to paid-in-kind distributions.
Selected Information from our Partnership Agreement
Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions, minimum quarterly distributions, paid-in-kind distributions and incentive distribution rights.
Available Cash
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.
Minimum Quarterly Distribution
The partnership agreement provides that, during the Subordination Period, the common units are entitled to distributions of available cash each quarter in an amount equal to the minimum quarterly distribution, which is $0.3375 per common unit for each full fiscal quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Furthermore, arrearages do not apply to and therefore will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the Subordination Period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to the minimum quarterly distribution.
The Subordination Period will lapse at such time when the Partnership has earned and paid at least the minimum quarterly distribution per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2013. Also, if the Partnership has earned and paid at least 150 percent of the minimum quarterly distribution on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the Subordination Period will terminate automatically. The Subordination Period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of removal. When the Subordination Period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages. All subordinated units are held indirectly by affiliates of our general partner.
Class B Units
The Class B units are not entitled to cash distributions. Instead, prior to conversion into common units, the Class B units will receive quarterly distributions of additional paid-in-kind Class B units. The amount of each quarterly distribution per Class B unit will be 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 the holder of such Class B unit or us 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.
Class C Units
The Class C units are entitled to quarterly cash distributions after the common units have received the minimum quarterly distribution, plus any arrearages from prior quarters. The Class C units will participate pro rata thereafter with all outstanding subordinated units until the subordinated units and Class C units receive the minimum quarterly distribution, after which the Class C units will participate in further cash distributions pro rata with our 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 will become convertible at the election of either the holder of such Class C unit or us into a common unit on a one-for-one basis. In the event of our liquidation, the holder of Class C 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 C units, determined after allocating our net income or net loss among the partners. All Class C units are held indirectly by affiliates of our general partner.
General Partner Interest and Incentive Distribution Rights
Our general partner is entitled to two percent of all quarterly distributions that we make after inception and prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its two percent general partner interest. Our general partner’s initial two percent interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon conversion of outstanding subordinated, Class B or Class C units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us to maintain its two percent general partner interest.
Other Securities Matters
Securities Authorized for Issuance Under Equity Compensation Plans.
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.
Unregistered Securities
On December 20, 2012, we sold (i) 5,929,025 Convertible Class B Units to each of Williams and the GIP II Entities and (ii) 5,599,634 Subordinated 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 Convertible Class B Units and the Subordinated Class C Units, inclusive of the capital contribution made by the general partner to maintain its two percent interest in the Partnership. In connection with a public offering of the Partnership’s common units in December 2012, the general partner made an additional capital contribution to the Partnership of $12.1 million to maintain its two percent interest in the Partnership. 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, 2012, we did not sell or issue any other equity securities without the registration of these securities under the Securities Act of 1933, as amended, in reliance on exemptions from such registration requirements, which have not been previously disclosed in a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.
ITEM 6.
ITEM 6. Selected Financial Data
The following table shows our selected financial and operating data for the periods and as of the dates indicated, which is derived from our consolidated financial statements. On August 3, 2010, we closed our IPO of 24,437,500 common units, including 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option. Upon completion of the IPO, Chesapeake and 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.
(1) If Chesapeake or Total does not meet its minimum volume commitment to the Partnership in the Barnett Shale region or Chesapeake does not meet its minimum volume commitments in the Haynesville Shale region under the applicable gas gathering agreement for specified annual periods, Chesapeake or Total is obligated to pay the Partnership a fee equal to the applicable fee for each one thousand cubic feet (“Mcf”) by which the applicable party’s minimum volume commitment for the year exceeds the actual volumes gathered on the Partnership’s systems. The Partnership recognizes any associated revenue in the fourth quarter. Our revenues for the three months ended December 31, 2009, include the impact of $7.7 million associated with the minimum volume commitment in our Barnett Shale region for 2009. For the years ended December 31, 2011 and 2010, we recognized revenue related to volume shortfall of $17.4 million and $56.8 million, respectively, because throughput in our Barnett Shale region was below contractual minimum volume commitment levels. No revenue associated with minimum volume commitments was recognized in 2012 as volumes exceeded commitment levels.
(2) Our predecessor recorded an $86.2 million impairment associated with certain Mid-Continent gathering systems that are not expected to have future cash flows in excess of the book value of the systems. These systems were subsequently contributed to us as of September 30, 2009. Additionally, $4 million of debt issuance costs were expensed as a result of the amendment of our predecessor’s $460 million credit facility. During the year ended December 31, 2008, our predecessor recorded a $30.0 million impairment associated with a certain treating facility as a result of the facility’s location in an area of continued declining throughput and a reduction in the future expected throughput volumes by Chesapeake, based on its revised future development plans on the associated oil and gas properties that serve as the primary source of throughput volumes for the facility.
(3) Our predecessor recorded a $44.6 million loss on the disposal of certain non-core and non-strategic gathering systems for the nine months ended September 30, 2009.
(4) Prior to February 2008, our predecessor filed a consolidated federal income tax return and state returns as required with Chesapeake. In February 2008, upon and subsequent to contribution of assets to our predecessor by Chesapeake, our predecessor and certain of its subsidiaries became a partnership and limited liability companies, respectively, and were subsequently treated as pass through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in our financial statements. As such, our predecessor has provided for the change in legal structure by recording an $86.2 million income tax benefit in 2008 at the time the change in legal structure occurred. This benefit was partially offset by income tax expense of $24.9 million, resulting in a net income tax benefit of $61.3 million for the year ended December 31, 2008. The income tax expense of $6.3 million for the nine months ended September 30, 2009 is related to our predecessor’s remaining taxable entity that was not contributed to us. Subsequent to September 30, 2009 income tax expense is entirely related to Texas Franchise Tax.
(5) The 2010 amounts are reflective of general and limited partner interests in net income after the closing our IPO on August 3, 2010.
(6) Adjusted EBITDA and distributable cash flow are defined under the heading Adjusted EBITDA and Distributable Cash Flow in Item 7
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Unless the context otherwise requires, references in this report to the “Partnership,” “we,” “our,” “us” or like terms, when used in a historical context, refer to the financial results of Chesapeake Midstream Partners, L.L.C. through the closing date of our initial public offering (“IPO”) on August 3, 2010 and to Access Midstream Partners, L.P. (NYSE: ACMP) and its subsidiaries thereafter. 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). “Chesapeake” refers to Chesapeake Energy Corporation (NYSE: CHK). “Total,” when discussing the upstream joint venture with Chesapeake, refers to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (NYSE: TOT, FP: FP), and when discussing our gas gathering agreement and related matters, refers to Total E&P USA, Inc. and Total Gas & Power North America, Inc., a wholly owned subsidiary of Total S.A.
Overview
We are a growth-oriented publicly traded Delaware limited partnership formed 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.
We provide our midstream services to Chesapeake, 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 our Barnett Shale region in north-central Texas; our Eagle Ford Shale region in South Texas; our Haynesville Shale region in northwest Louisiana; our Marcellus Shale region primarily in Pennsylvania and West Virginia; our Niobrara Shale region in eastern Wyoming; our Utica Shale region in eastern Ohio; and our Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian Basins.
Acquisitions
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, the Partnership now owns certain midstream assets in the Eagle Ford, Utica and Niobrara regions. The CMO Acquisition also extended our 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 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 closing of the Williams Acquisition, the GIP II Entities and Williams together own and control our general partner and the GIP I Entities no longer have any ownership interest in the Partnership or our general partner.
Our Marcellus Acquisition
On December 29, 2011, we acquired from CMD all of the issued and outstanding common units of 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 commitment in 2012.
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 2012 and the two-day period from closing of the acquisition on December 29, 2011, through December 31, 2011.
We acquired additional assets in the Marcellus Shale region through the acquisition of CMO in December 2012.
Our Haynesville Springridge Acquisition
On December 21, 2010, we acquired the Springridge gathering system and related facilities located in Caddo and De Soto Parishes, Louisiana from CMD for $500.0 million. In connection with the acquisition, we entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake that includes a significant acreage dedication, an annual fee redetermination and a three-year minimum volume commitment.
Our Operations
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 our Mid-Continent region, which includes the Anadarko, Arkoma, Delaware and Permian Basins.
We generated approximately 54 percent of our fees from our gathering systems in the Barnett Shale region, approximately 19 percent of our fees from our gathering systems in the Marcellus Shale region, approximately 18 percent of our fees from our gathering systems in our Mid-Continent region and approximately 9 percent of our fees from our gathering systems in the Haynesville Shale region for the year ended December 31, 2012. The CMO assets contributed to our income during the 12-day period from closing of the acquisition to December 31, 2012, but the impact was immaterial to our results.
The results of our operations are primarily driven by the volumes of natural gas and liquids we gather, treat, compress and process across our gathering systems. 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.
Our Commercial Agreements with Producers
We generate substantially all of our revenues through long-term, fixed-fee natural gas gathering, treating and compression contracts, and increasingly through processing contracts, all of which limit our direct commodity price exposure.
Future revenues 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 our Barnett Shale region for the fees and obligations outlined below:
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Gathering, Treating and Compression Services. We gather, treat and compress natural gas for Chesapeake and Total within the Barnett Shale region in exchange for specified fees per thousand cubic feet (“Mcf”) for natural gas gathered on our gathering systems that are based on the pressure at the various points where our gathering systems received our customers’ natural gas. We refer to these fees collectively as the Barnett Shale fee. Our Barnett Shale fee is subject to an annual rate escalation of two percent at the beginning of each year.
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Acreage Dedication. Pursuant to our gas gathering agreements, subject to certain exceptions, each of Chesapeake and Total has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on natural gas and oil leases covering lands within an acreage dedication in our Barnett Shale region.
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Minimum Volume Commitments. Pursuant to our gas gathering agreements, Chesapeake and Total have agreed to minimum volume commitments for each year through December 31, 2018 and for the six-month period ending June 30, 2019. Approximately 75 percent of the aggregate minimum volume commitment is attributed to Chesapeake, and approximately 25 percent is attributed to Total. The minimum volume commitments increase, on average, approximately 3 percent per year. The following table outlines the approximate aggregate minimum volume commitments for each year during the minimum volume commitment period:
(1) Indicated volumes relate to the six months ending June 30, 2019.
If either Chesapeake or Total does not meet its minimum volume commitment to us, as adjusted in certain instances, for any annual period (or six-month period in the case of the six months ending June 30, 2019) during the minimum volume commitment period, Chesapeake or Total, as applicable, will be obligated to pay us a fee equal to the Barnett Shale fee for each Mcf by which the applicable party’s minimum volume commitment for the year (or six-month period) exceeds the actual volumes gathered on our systems attributable to the applicable party’s production. To the extent natural gas gathered on our systems from Chesapeake or Total, as applicable, during any annual period (or six-month period) exceeds such party’s minimum volume commitment for the period, Chesapeake or Total, as applicable, will be obligated to pay us the Barnett Shale fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitments for the six months ending June 30, 2019, and then against the minimum volume commitments of each preceding year. If the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the final day of the immediately preceding period.
•
Fee Redetermination. In May 2012, we entered into an agreement with Chesapeake and Total relating to the initial redetermination period. The agreement called for an upward adjustment of the Barnett Shale fee and was effective July 1, 2012. We and each of Chesapeake and Total, as applicable, have the right to request an additional redetermination of the Barnett Shale fee during a two-year period beginning on September 30, 2014. The fee redetermination mechanism is intended to support a return on our invested capital. If a fee redetermination is requested, we will determine an adjustment (upward or downward) to our Barnett Shale fee with Chesapeake and Total based on the factors specified in our gas gathering agreements, including, but not limited to: (i) differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the minimum volume commitment period made as of September 30, 2009 and (ii) differences between the revised estimates of our capital expenditures, compression expenses and revenues for the remainder of the minimum volume commitment period forecast as of the redetermination date and scheduled estimates thereof for the minimum volume commitment period made as of September 30, 2009. The cumulative upward or downward adjustment for the Barnett Shale region is capped at 27.5 percent of the initial weighted average Barnett Shale fee (as escalated) as specified in the gas gathering agreement. If
we and Chesapeake or Total, as applicable, do not agree upon a redetermination of the Barnett Shale fee within 30 days of receipt of the request for the redetermination, an industry expert will be selected to determine adjustments to the Barnett Shale fee.
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Well Connection Requirement. Subject to required notice by Chesapeake and Total and certain exceptions, we have generally agreed to connect new operated drilling pads and new operated wells within our Barnett Shale region acreage dedications as requested by Chesapeake and Total during the minimum volume commitment period. During the minimum volume period, if we fail to complete a connection in the acreage dedication by the required date, Chesapeake and Total, as their sole remedy for such delayed connection, are entitled to a delay in the minimum volume obligations for gas volumes that would have been produced from the delayed connection.
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Fuel and Lost and Unaccounted For Gas. We have agreed with Chesapeake and Total on caps on fuel and lost and unaccounted for gas on our systems, both on an individual basis and an aggregate basis, with respect to Chesapeake’s and Total’s volumes. These caps do not apply to certain of our gathering systems due to their historic performance relative to the caps. These systems will be reviewed annually to determine whether changes have occurred that would make them suitable for inclusion. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel and lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.
Eagle Ford Shale Region. Under our gas gathering agreement that we entered into with our producer customer, as part of the CMO Acquisition, we have agreed to provide the following services in our Eagle Ford Shale region for the fees and obligations outlined below:
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Gathering, Compression, Dehydration and Treating Services. We will gather, compress, dehydrate and treat natural gas and liquids for the producers within the Eagle Ford Shale region in exchange for a cost of service based fee for natural gas and liquids gathered and treated on our gathering systems. The cost of service components will include revenue, compression expense, deemed general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics. We refer to these fees collectively as the Eagle Ford fee.
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Acreage Dedication. Subject to certain exceptions, our producer customer has agreed to dedicate all of the natural gas and liquids owned or controlled by it and produced from the Eagle Ford Shale formation through existing and future wells with a surface location within the dedicated area in the Eagle Ford Shale region.
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Fee Redetermination. During 2013 and 2014, the Eagle Ford fee is determined by a fee tiering mechanism that calculates the Eagle Ford fee on a monthly basis according to the quantity of gas delivered to us by our producer customer relative to its scheduled deliveries. Effective on January 1, 2015 and January 1 of each year thereafter for a period of 20 years from July 1, 2012, the Eagle Ford fee will be redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital. There is no cap on these adjustments.
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Well Connection Requirement. Subject to required notice by our producer customer, we will have the option to connect new operated wells within our Eagle Ford Shale region acreage dedications as requested by the producer customer. If we elect not to connect a new operated well, the producer customer will be provided alternative forms of release. Subject to certain conditions specified in the applicable gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections, up to a specified cap, and the potential for a well pad release from the producer customer’s acreage dedication in certain circumstances.
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Fuel and Lost and Unaccounted For Gas. We have agreed with the producer customer to a cap on fuel and lost and unaccounted for gas on our systems with respect to the producer customer’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period and do not respond in a timely manner with a proposed solution, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then-current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.
Haynesville Shale Region. Under our gas gathering agreement that we entered into with our producer customer, we have agreed to provide the following services in our Haynesville Shale region for the fees and obligations outlined below:
Springridge Gathering System
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Gathering, Treating and Compression Services. We gather, treat and compress natural gas in exchange for fees per Mcf for natural gas gathered and per Mcf for natural gas compressed, which we refer to as the Springridge fees. The Springridge fees for these systems are subject to an annual specified rate escalation at the beginning of each year.
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Minimum Volume Commitments. Pursuant to our gas gathering agreement, our producer customer has agreed to minimum volume commitments for each year through December 31, 2013. In the event our producer customer does not meet its minimum volume commitment to us, as adjusted in certain instances, for any annual period during the minimum volume commitment period, it will be obligated to pay us a fee equal to the Springridge fee for each Mcf by which the minimum volume commitment for the year exceeds the actual volumes gathered on our systems attributable to its production. To the extent natural gas gathered on our systems from our producer customer during any annual period exceeds its minimum volume commitment for the period, it will be obligated to pay us the Springridge fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitments for the year 2013, and then against the minimum volume commitments of each preceding year. In the event that the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the final day of the immediately preceding period.
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Acreage Dedication. Pursuant to our gas gathering agreement, subject to certain exceptions, our producer customer has agreed to dedicate all of the natural gas owned or controlled by them and produced from or attributable to existing and future wells located on oil, natural gas and mineral leases within the Springridge acreage dedication.
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Fee Redetermination. The Springridge fees are subject to a redetermination mechanism. The first redetermination period will extend from December 1, 2010 through December 31, 2012, and subsequent redetermination periods will be the calendar years 2013 through 2020. We will determine an adjustment to fees for the gathering systems in the region with our producer customer based on the factors specified in the gas gathering agreement, including, but not limited to, differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the period ending December 31, 2020, referred to as the redetermination period, made as of November 30, 2010. The annual upward or downward fee adjustment for the Springridge region is capped at 15 percent of the then-current fees at the time of redetermination.
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Well Connection Requirement. We have certain connection obligations for new operated drilling pads and operated wells of our producer customer in the acreage dedications. Our producer customer is required to provide us notice of new drilling pads and wells operated by our producer customer in the acreage dedications. Subject to certain conditions specified in the gas gathering agreement, we are generally required to connect new operated drilling pads in the acreage dedication by the later of 30 days after the date the wells commence production and six months after the date of the connection notice. During the
minimum volume period, if we fail to complete a connection in the Springridge acreage dedication by the required date, our producer customer, as its sole remedy for such delayed connection, is entitled to a delay in the minimum volume obligations for gas volumes that would have been produced from the delayed connection. After the minimum volume period, we are subject to a daily penalty for such delayed connections, up to a specified cap per delayed connection. Our producer customer also is required to notify us of its wells drilled in the acreage dedications that are operated by other parties and we have the option, but not the obligation, to connect non-operated wells to our gathering systems. If we decline to make a connection to a non-operated well, our producer customer has certain rights to have the well released from the dedication under the gas gathering agreement.
• Fuel and Lost and Unaccounted For Gas. We have agreed with our producer customer on caps on fuel and lost and unaccounted for gas on our systems with respect to our producer customer’s volumes. These caps do not apply to one of our compressor stations due to its historical performance relative to the caps. This station will be reviewed periodically to determine whether changes have occurred that would make it suitable for inclusion. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.
Mansfield Gathering System
• Gathering, Dehydration, Compression and Treating Services. We will gather, dehydrate, compress and to the extent provided, treat natural gas in exchange for a fixed fee per MMBtu for natural gas gathered. We refer to this fee as the Mansfield fee. The Mansfield fee is subject to an annual 2.5 percent rate escalation at the beginning of each year.
• Acreage Dedication. Subject to certain exceptions, our producer customer has agreed to dedicate all of the natural gas owned or controlled by it and produced from the Bossier and Haynesville formations through existing and future wells with a surface location within the dedicated area in the Mansfield acreage dedication.
• Minimum Volume Commitments. Pursuant to our gas gathering agreement, our producer customer has agreed to minimum volume commitments for each year through December 31, 2017. If our producer customer does not meet its minimum volume commitments to us, as adjusted in certain instances, for any annual period during the minimum volume commitment period, it will be obligated to pay us the difference between the minimum volume commitment and the volume of gas delivered from its wells.
• Fixed Fee/Tiered Fees. During the minimum volume commitment period, the Mansfield fee is a fixed fee on all monthly volumes. Subsequent to that period, our producer customer will pay a tiered fee that calculates the Mansfield fee on a monthly basis according to the quantity of gas delivered to us from our producer customer’s wells relative to its scheduled deliveries.
• Well Connection Requirement. We have certain connection obligations for new operated wells of our producer customer in the acreage dedications. Our producer customer is required to provide us notice of new wells that it operates in the acreage dedications. Subject to certain conditions specified in the applicable gas gathering agreement, we are generally required to connect new wells within specified timelines subject to minimum volume commitment delays for volumes that would have been received from the new wells during the minimum volume commitment period and penalties up to a specified cap after the minimum volume commitment period.
• Fuel and Lost and Unaccounted For Gas. We have agreed with our producer customer on percentage-based caps on fuel and lost and unaccounted for gas on our systems with respect to our producer customer’s volumes. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.
Marcellus Shale Region. Under our gas gathering agreements with certain subsidiaries of Chesapeake, Statoil, Anadarko, Epsilon, Mitsui and Chief, we have agreed to provide the following services in our Marcellus Shale region for our proportionate share (based on our ownership interest in the applicable systems) of the fees and obligations outlined below:
• Gathering and Compression Services. In systems operated by Appalachia Midstream, we gather and compress natural gas in exchange for fees per million British thermal units (“MMBtu”) of natural gas gathered and per MMBtu of natural gas compressed. The gathering fees are redetermined annually based on a cost of service mechanism, as described below. The compression fees escalate on January 1 of each year based on the consumer price index. In addition, CMD has committed to pay us quarterly any shortfall between the actual EBITDA generated by these assets and specified quarterly targets totaling $100 million in 2012 and $150 million in 2013. EBITDA generated by these assets exceeded the $100 million target for 2012 and no additional revenue related to the commitment was recognized. The target for 2013 represents the minimum amount of EBITDA we will recognize with the potential that throughput for these systems will generate EBITDA in excess of the guaranteed amounts. The following table below outlines the EBITDA commitments for each quarter during the commitment period. In the systems acquired as part of the CMO Acquisition, we gather and compress natural gas in exchange for a gathering fee per MMBtu, which is redetermined annually based on a cost of service mechanism.
• Acreage Dedication. Pursuant to our gas gathering agreements, subject to certain exceptions, the shippers and producers have agreed to dedicate all of the natural gas owned or controlled by them and produced from or attributable to existing and future wells with a surface location within the designated dedicated areas.
• Fee Redetermination. Each January 1, gathering fees for each gathering system under the gas gathering agreements with Chesapeake, Statoil, Anadarko, Epsilon and Mitsui will be redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital. There is no cap on these fee adjustments. Each January 1, gathering fees for each gathering system under the gas gathering agreement with Chief are adjusted based on the applicable producer price index. The change in the amount of the gathering fees under the Chief agreement is not to exceed 3 percent in any one year.
• Well Connections. We have the option to connect to new wells within the dedicated acreage. If we elect not to connect to any new well within the dedicated acreage, the shipper for such well may elect to have such well, and any subsequent wells within a two-mile radius (in the case of Chesapeake, Statoil, Anadarko, Epsilon and Mitsui) or a one-mile radius (in the case of Chief) of the surface location of such well, permanently released from the dedication area, or the shipper may elect to construct, at the shipper’s expense, a gathering system to connect to such well (and wells within a one-mile radius of such well in the case of Chesapeake, Statoil, Anadarko, Epsilon and Mitsui), in which case the shipper would pay us a reduced gathering fee for natural gas we receive through the shipper-installed asset. Alternatively, the shipper may require us to enter into an agreement pursuant to which we would construct the gathering system to connect to the well in exchange for a reimbursement by the shipper of the costs we incur in connection therewith. The shipper may elect to connect wells outside the dedicated area at its sole expense and pay us a reduced gathering fee for natural gas we receive from such wells, but gas from such outside wells will not be afforded the same priority as gas produced from wells located within the dedicated area. In the systems acquired as part of the CMO Acquisition, subject to certain conditions specified in the applicable gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections, up to a specified cap, and the potential for a well pad release from the producer’s acreage dedication in certain circumstances.
• Fuel and Lost and Unaccounted For Gas. Under our gas gathering agreements with Chesapeake, Statoil, Anadarko, Epsilon and Mitsui, we have agreed on caps on fuel and lost and unaccounted for gas on the systems. If we exceed the permitted cap, we must provide a cost estimate for a remedy that is reasonably expected to prevent exceeding the permitted cap in the future. At the election of the shippers we may pay such costs (which costs would then be included in the gathering fee redetermination) or the shippers may pay the costs. If we exceed the permitted cap and do not provide a proposal to the shippers to prevent exceeding the cap in the future within the required time period, we may incur our proportionate share (based on our ownership interest in the applicable system) of significant expenses in connection with the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this may subject us to direct commodity price risk.
Under gas gathering agreements between Appalachia Midstream and certain subsidiaries of Chief, the shipper on each system is to furnish to us, at the shipper’s sole cost and expense, all necessary fuel gas to operate the system. Gas volumes lost solely due to our actions or inactions constituting gross negligence or willful misconduct are our sole responsibility. Additionally, we will bear the cost of natural gas lost in excess of one percent due to our failure to maintain adequate corrosion protection. If we lose natural gas due to our gross negligence or willful misconduct or our failure to maintain an adequate corrosion protection system, we may incur significant expenses in connection with the cost of the lost natural gas. Our responsibility for the cost of the lost gas may subject us to direct commodity price risk.
Niobrara Shale Region. Under our gas gathering and processing agreement that we entered into with our producer customer, as part of the CMO Acquisition, we have agreed to provide the following services in our Niobrara Shale region for the fees and obligations outlined below:
• Gathering, Compression, Dehydration and Processing Services. We will gather, compress, dehydrate and process natural gas and liquids within the Niobrara region in exchange for a cost of service based fee for natural gas and liquids gathered on our gathering systems and for natural gas and liquids processed at our proposed processing facility. The cost of service components will include revenues, compression expense, deemed general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics. We refer to these fees collectively as the Niobrara fee.
• Acreage Dedication. Subject to certain exceptions, our producer customer has agreed to dedicate all of the natural gas and liquids owned or controlled by them and produced from the Frontier Sand and the Niobrara Shale through existing and future wells with a surface location within the dedicated areas in the Niobrara Shale region.
• Fee Redetermination. Effective on January 1, 2014 and January 1st of each year thereafter for a period of 20 years from July 1, 2012, the Niobrara fee will be redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital. There is no cap on these fee adjustments.
• Well Connections. Subject to required notice by our producer customer, we will have the option to connect new operated wells within our Niobrara region acreage dedications as requested by such producer customer. If we elect not to connect a new operated well, the producer customer will be provided alternative forms of release. Subject to certain conditions specified in the gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections up to a specified cap, and the potential for a well pad release from the producer customer’s acreage dedication in certain circumstances.
• Fuel and Lost and Unaccounted For Gas. We have agreed with our producer customer to a cap on fuel and lost and unaccounted for gas on our systems with respect to the producer customer’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period and do not respond in a timely manner with a proposed solution, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.
Utica Shale Region. Under our commercial agreements that we entered into with Chesapeake, Total and Enervest, acquired as part of the CMO Acquisition, we have agreed to provide the following services in our Utica Shale region to our producer customers for the fees and obligations of our producer customers outlined below:
• Gathering, Compression, Dehydration, Processing and Fractionation Services. We will gather, compress and dehydrate natural gas and liquids in exchange for a cost of service based fee for natural gas and liquids gathered on our gathering systems. The cost of service components (i) for our 66 percent operating interest in a joint venture that owns five wet gas gathering systems (the “Cardinal JV”), and (ii) in the area covered
by our 100 percent ownership interest in four dry gas gathering systems (the “Utica Dry”) will include revenues, compression expense (in the case of the Utica Dry only), deemed general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics. We also will process and fractionate natural gas and liquids through our 49 percent non-operating interest in a joint venture that is currently constructing four 200 MMcf/d processing trains, a 120,000 barrel per day fractionation facility, approximately 870,000 barrels of NGL storage capacity and other ancillary assets (the “UEO JV”) for a fixed fee that escalates annually within a specified range. The Partnership refers to these fees collectively as the Utica fee.
• Acreage Dedication. Subject to certain exceptions, our producer customers have agreed to dedicate all of the natural gas and liquids owned or controlled by them and produced from the Utica Shale formation through existing and future wells with a surface location within the dedicated areas in the Utica Shale region. The UEO JV has a processing and fractionation dedication with a designated dedication area from Chesapeake, Total and Enervest for 800 MMcf/d.
• Fee Redetermination. Beginning on October 1, 2013 for the Cardinal JV and January 1, 2014 for Utica Dry and annually thereafter, for a period of 20.75 years from January 1, 2012 (Cardinal JV) and 15 years from July 1, 2012 (Utica Dry), the gathering fee portion of the Utica fee will be redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital. There is no cap on these fee adjustments.
• Well Connections. In the Cardinal JV, we are generally required to connect new wells within specified timelines subject to penalties for delayed connections in the form of a temporary reduction in the gathering fee for the new well. In Utica Dry, subject to required notice by the producer customer, we will have the option to connect new operated wells within our dedicated acreage as requested by the producer customer. If we elect not to connect a new operated well, the producer customer will be provided alternative forms of release. Subject to certain conditions specified in the gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections, up to a specified cap, and the potential for a well pad release from the producer’s acreage dedication in certain circumstances.
• Processing and Fractionation Performance Standards. We have agreed with our producer customers to certain performance standards for the UEO JV, including guaranteed in-service dates, minimum facility run-time standards, minimum propane recovery standards, and fuel caps. If the UEO JV fails to achieve any of these performance standards as specified, the fees associated with these services will be temporarily reduced.
• Fuel and Lost and Unaccounted For Gas. We have agreed with the producer customers to a cap on fuel and lost and unaccounted for gas on our systems with respect to each producer’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk. In Utica Dry, exceeding the permitted cap does not result in a reimbursement to the Utica producers if we respond in a timely manner with a proposed solution.
Mid-Continent Region. Under our gas gathering agreement with producer customers, we have agreed to provide the following services in our Mid-Continent region to our producer customers for the fees and obligations of our producer customers outlined below:
• Gathering, Treating and Compression and Processing Services. We gather, treat, compress and process natural gas and NGLs in exchange for system-based services fees per Mcf for natural gas gathered and per Mcf for natural gas compressed. We refer to the fees collectively as the Mid-Continent fee. The Mid-Continent fees for these systems are subject to an annual two and a half percent rate escalation at the beginning of each year.
• Acreage Dedication. Pursuant to our gas gathering agreement, subject to certain exceptions, our producer customers have agreed to dedicate all of the natural gas and liquids owned or controlled by them and produced from or attributable to existing and future wells located on oil, natural gas and mineral leases covering lands within the acreage dedication.
• Fee Redetermination. The Mid-Continent fees are redetermined at the beginning of each year through 2019. We and our producer customers will determine an adjustment to fees for the gathering systems in the region with our producer customers based on the factors specified in the gas gathering agreement,
including, but not limited to, differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the period ending June 30, 2019, referred to as the redetermination period, made as of September 30, 2009. The annual upward or downward fee adjustment for the Mid-Continent region is capped at 15 percent of the then current fees at the time of redetermination.
• Well Connection Requirement. Subject to required notice by our producer customers and certain exceptions, we have generally agreed to use our commercially reasonable efforts to connect new operated drilling pads and new operated wells in our Mid-Continent region acreage dedications as requested by our producer customers through June 30, 2019.
• Fuel and Lost and Unaccounted For Gas. We have agreed with our producer customers on caps on fuel and lost and unaccounted for gas on our systems, both on an individual basis and an aggregate basis, with respect to our producer customers volumes. These caps do not apply to certain of our gathering systems due to their historic performance relative to the caps. These systems will be reviewed annually to determine whether changes have occurred that would make them suitable for inclusion. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.
As part of the CMO Acquisition, we acquired a 33% 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 gas processing services under a cost of service fee arrangement.
All Regions. If one of the counterparties to the gas gathering agreements sells, transfers or otherwise disposes of to a third party properties within the our acreage dedications, it does so subject to the terms of the gas gathering agreement, 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 agreement with the Partnership, subject to our consent. Our producer customers’ dedication of the gas produced from applicable properties under our gas gathering 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.
Other Arrangements
Services Arrangements. Under our services agreement with Chesapeake, Chesapeake has agreed to provide us with certain general and administrative services and any additional services we may request. We reimburse Chesapeake for such general and administrative services in any given month subject to a cap equal to $0.0310 per Mcf multiplied by the volume (measured in Mcf) of natural gas and liquids that we gather, treat or compress. The fee is calculated as the lesser of $0.0310 per Mcf gathered or actual corporate overhead costs, excluding those overhead costs that are billed directly to the Partnership. The $0.0310 per Mcf cap is subject to an annual upward adjustment on October 1 of each year equal to 50 percent of any increase in the Consumer Price Index, and, subject to receipt of requisite approvals, such cap may be further adjusted to reflect changes in general and administrative services provided by Chesapeake relating to new laws or accounting rules that are implemented. The cap contained in the services agreement does not apply to our direct general and administrative expenses.
Additionally, pursuant to an employee secondment agreement, specified employees of Chesapeake were seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Our general partner, subject to specified exceptions and limitations, reimbursed Chesapeake on a monthly basis for substantially all costs and expenses it incurred relating to such seconded employees.
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 the Partnership (the “GIP Acquisition”), we entered into a letter agreement with Chesapeake regarding the terms on which Chesapeake will provide certain transition services to the Partnership and our general partner following the GIP Acquisition by the GIP II Entities. Among other things, the letter agreement provides for the continuation of our services agreement and secondment 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 and altering the workers’ compensation insurance endorsements for our general partner under our secondment agreement. On December 20, 2012 in connection with the CMO Acquisition, we entered into another 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. The secondment agreement and employee transfer agreement each terminated on January 1, 2013.
How We Evaluate Our Operations
Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (i) throughput volumes, (ii) revenues, (iii) operating expenses, (iv) Adjusted EBITDA and (v) distributable cash flow.
Throughput Volumes
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.
Revenues
Our revenues are driven primarily by our contractual terms with our customers and the actual volumes of natural gas we gather, treat and compress, and increasingly by the actual volumes of natural gas we 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 natural gas or liquids from individual wells located near our gathering systems. We connect wells to gathering pipelines through which natural gas is compressed and may be delivered to a treating facility, processing plant or an intrastate or interstate pipeline for delivery to market. We treat natural gas and liquids that we gather to the extent necessary to meet required specifications of third-party takeaway pipelines. For the years ended December 31, 2012, 2011 and 2010, Chesapeake accounted for approximately 81 percent, 84 percent and 81 percent, respectively, of the natural gas volumes on our gathering systems and 81 percent, 83 percent and 82 percent, respectively, of our revenues. Across all operating regions, we earned approximately 75.3 percent of our fees from Chesapeake and 24.7 percent from other producer customers for the year ended December 31, 2012.
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.
Operating Expenses
Our management seeks to maximize the profitability of our operations by minimizing operating expenses without compromising environmental protection and employee safety. Operating expenses are comprised primarily of field operating costs (which include labor, treating and chemicals, and 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.
Adjusted EBITDA and Distributable Cash Flow
We define Adjusted EBITDA as net income (loss) before income tax expense (benefit), interest expense, depreciation and amortization expense and certain other items management believes effect the comparability of operating results.
We define distributable cash flow as Adjusted EBITDA, plus interest income, less cash paid for interest expense, maintenance capital expenditures and income taxes. Distributable cash flow does not reflect changes in working capital balances. Distributable cash flow and Adjusted EBITDA are not presentations made in accordance with generally accepted accounting principles (“GAAP”).
We did not utilize a distributable cash flow measure prior to becoming a publicly traded partnership in 2010 and, as such, did not differentiate between maintenance and capital expenditures prior to 2010 and do not report distributable cash flow for periods prior to 2010.
Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:
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our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis, or in the case of Adjusted EBITDA, financing methods;
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our ability to incur and service debt and fund capital expenditures;
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the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and
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the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
Reconciliation to GAAP measures
We believe that the presentation of Adjusted EBITDA and distributable cash flow provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and distributable cash flow are presented because they are helpful to management, industry analysts, investors, lenders and rating agencies and may be used to assess the financial performance and operating results of our fundamental business activities. The GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow are net income and net cash provided by operating activities. Our non-GAAP financial measures of Adjusted EBITDA and distributable cash flow should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Each of Adjusted EBITDA and distributable cash flow has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. You should not consider either Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted 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:
Results of Operations
We have provided a detailed comparison for the years ended December 31, 2012, 2011 and 2010 in the chart and discussion below. The following table and discussion present a summary of our financial results of operations for the periods described above:
(1) If either Chesapeake or Total does not meet its minimum volume commitment to the Partnership in the Barnett Shale region or Chesapeake does not meet its minimum volume commitment in the Haynesville Shale region under the applicable gas gathering agreement for specified annual periods, Chesapeake or Total is obligated to pay the Partnership a fee equal to the applicable fee for each Mcf by which the applicable party’s minimum volume commitment for the year exceeds the actual volumes gathered on the Partnership’s systems. The Partnership recognizes any associated revenue in the fourth quarter. For the years ended December 31, 2011 and 2010, we recognized revenue related to volume shortfall of $17.4 million and $56.8 million, respectively, because throughput in our Barnett Shale region was below contractual minimum volume commitment levels.
(2) Excludes production from CMO assets acquired on December 20, 2012.
Year Ended December 31, 2012 vs. Year Ended December 31, 2011
Revenues. Our revenues are primarily attributable to the amount of throughput on our gathering systems and the rates charged for gathering such throughput. For the years ended December 31, 2012 and 2011, revenues were $608.4 million and $565.9 million, respectively. The increase was primarily the result of increased throughput in our Barnett Shale region and an increase in rates in our Mid-Continent region. These factors more than offset a decrease in throughput on our Springridge gathering system in the Haynesville Shale. Barnett Shale throughput increased 10.6 percent due to additional throughput from wells connected in 2011 and the first half of 2012. Our Barnett Shale fees increased five cents per mcf effective July 1, 2012, as a result of fee redetermination. The increases in throughput and rate generated a 9.3 percent increase in revenues. Springridge gathering system throughput was down 33.5 percent as a result of decreased drilling activity and natural declines in this region. Revenues in the Springridge gathering system were down 30.0 percent as a 2.5 percent annual fee escalation and some temporary third-party throughput at higher fees partially offset the volume decrease. Mid-Continent throughput increased 2.5 percent as drilling activity has increased in this liquids-rich region. The volume increase, a 2.5 percent annual fee escalation and a 15 percent fee increase due to annual contractual fee redetermination helped Mid-Continent revenues increase more than 22.8 percent.
We have contractual minimum volume commitments from Chesapeake and Total in the Barnett Shale and from Chesapeake in the Haynesville Shale. Throughput in these regions during the current year was above the minimum volume commitment levels. 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.
The table below reflects revenues and throughput by region for the year ended December 31, 2012 compared to the year ended December 31, 2011:
(1) N.M.-not meaningful
(2) Reflective of revenue after completion of the CMO Acquisition, from December 20, 2012, through December 31, 2012.
Operating Expenses. Operating expenses were $0.25 per Mcf for the year ended December 31, 2012, compared to $0.22 per Mcf for the year ended December 31, 2011. In the Barnett Shale region, throughput has increased and operating expenses have increased in order to generate the additional throughput. 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. In the Mid-Continent region, operating expenses have increased due to added compression that has generated additional revenue as well as spending in preparation for increased drilling activity in this liquids-rich region.
The table below reflects our total operating expenses and operating expenses per Mcf of throughput by region for the year ended December 31, 2012 compared to the year ended December 31, 2011:
(1) N.M.-not meaningful
(2) Reflective of operating expenses after completion of the CMO Acquisition, from December 20, 2012, through December 31, 2012.
Depreciation and Amortization Expense. Depreciation expense for the year ended December 31, 2012 increased 23.3 percent to $153.8 million from $124.7 million for the year ended December 31, 2011. Amortization expense for the year ended December 31, 2012 increased 1.7 percent to $11.7 million from $11.5 million for the year ended December 31, 2011. The increase in depreciation expense is a result of capital expenditures made in 2012.
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 the Partnership’s operations, additional expense from equity-based, long-term incentive compensation influenced by the recent increase in the Partnership’s unit price, one-time transition costs as the Partnership develops 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.
Income from unconsolidated affiliates. On December 29, 2011, we acquired all of the issued and outstanding common units of Appalachia Midstream, which owns an approximate average 47 percent interest in 10 gas gathering systems in the Marcellus Shale in Pennsylvania and West Virginia. The remaining 53 percent interest in these assets are owned primarily by Statoil, Anadarko, Epsilon and Mitsui. As part of the CMO Acquisition in December 2012, we acquired a 49 percent interest in Utica East Ohio Midstream LLC 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 and a 33 percent interest in Ranch Westex JV, LLC. with Regency Energy Partners, LP and Anadarko Pecos Midstream LLC to build a processing facility in Ward County, Texas. Income from unconsolidated affiliates was $67.5 million and $0.4 million reflecting activity for the year ended December 31, 2012 and the last two days of December 2011, respectively.
Year Ended December 31, 2011 vs. Year Ended December 31, 2010
Revenues. For the years ended December 31, 2011 and 2010, our throughput was 2.2 Bcf per day and 1.6 Bcf per day, respectively. The increase in our throughput was primarily due to the acquisition of Springridge at the end of 2010. Revenues were $565.9 million and $459.2 million, respectively, an increase of 23.2 percent. Revenues were positively impacted by the redetermination of Mid-Continent gathering rates that occurred on January 1, 2011, increasing gathering rates in that region by approximately 15 percent. Gathering rates increased two percent in the Barnett Shale and two and a half percent in the Mid-Continent region as a result of annual contractual rate increases. We also benefited from added compression revenues during 2011 as well as additional revenues resulting from the significant number of well connects completed during the year. For the years ended December 31, 2011 and 2010, we connected 610 and 427 new wells, respectively.
Because throughput in the Barnett Shale during 2011 and 2010 was below contractual minimum volume commitment levels, we recognized revenue related to volume shortfall of $17.4 million and $56.8 million for the years ended December 31, 2011 and 2010, respectively. The amount recognized in 2010 included a one-time carry forward from 2009 of $17.2 million. The minimum volume commitment is measured annually and recognized in the fourth quarter of each year.
The table below reflects revenues and throughput by region for the year ended December 31, 2011 compared to the year ended December 31, 2010:
(1) N.M.-not meaningful
Operating Expenses. Operating expenses were $0.22 per Mcf for the year ended December 31, 2011 compared to $0.23 per Mcf for the year ended December 31, 2010. Despite the overall decrease, we have experienced an increase in both the Barnett Shale and Mid-Continent regions due to additional compression expense that has increased our overall throughput capacity and associated revenue. We have also incurred increased expenses for additional field personnel and other personnel related costs resulting from Partnership growth.
The table below reflects our total operating expenses and operating expenses per Mcf of throughput by region for the year ended December 31, 2011 compared to the year ended December 31, 2010:
(1) N.M.-not meaningful
Depreciation and Amortization Expense. Depreciation expense for the year ended December 31, 2011 increased 40.7 percent to $124.7 million from $88.6 million for the year ended December 31, 2011. Amortization expense for the year ended December 31, 2011 was $11.5 million. The increase in depreciation and amortization is a result of capital expenditures made in 2010 and early 2011 and the acquisition of the Springridge gathering system in the Haynesville Shale at the end of 2010.
General and Administrative Expense. For the years ended December 31, 2011 and 2010, general and administrative expenses were $40.4 million and $32.0 million, respectively, representing an increase of 26.2 percent. The increase is primarily attributable to additional expenses resulting from the acquisition of the Springridge gathering system in the Haynesville Shale.
Interest Expense. Interest expense for the year ended December 31, 2011 was $14.9 million, which was net of $9.5 million of capitalized interest. Interest expense was $7.4 million for the year ended December 31, 2010, which was net of $2.6 million of capitalized interest. The increase is related to interest expense on the senior notes issued in April 2011. We incur interest expense on our senior notes, borrowings under our revolving credit facility and commitment fees on the unused portion of the credit facility. Interest expense also includes amortization of previously capitalized debt issuance costs.
Income Tax Expense. Income tax expense for the years ended December 31, 2011 and 2010 was $3.3 million and $2.4 million, respectively, and was attributable to franchise taxes in the state of Texas. The Partnership and its subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the financial statements, other than Texas Franchise Tax.
Income from unconsolidated affiliates. On December 29, 2011, we acquired all of the issued and outstanding common units of Appalachia Midstream, which owns an approximate average 47 percent interest in 10 gas gathering systems in the Marcellus Shale in Pennsylvania and West Virginia. The remaining 53 percent interest in these assets is owned primarily by Statoil, Anadarko, Epsilon and Mitsui. Income from unconsolidated affiliates was $0.4 million reflecting activity for the last two days of December 2011.
Liquidity and Capital Resources
Our ability to finance operations and fund capital expenditures will largely depend on our ability to generate sufficient cash flow to cover these expenses as well as the availability of borrowings under our revolving credit facility and our access to the capital markets. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. See Risk Factors in Item 1A of this annual report.
Historically, our sources of liquidity included cash generated from operations and borrowings under our revolving credit facility.
Working Capital (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, 2012 and 2011, we had working capital deficits of $44.0 million and $54.9 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, 2012 and 2011 were as follows:
Operating Activities. Net cash provided by operating activities was $318.1 million for the year ended December 31, 2012 compared to $399.0 million for the year ended December 31, 2011. 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, 2012 increased $1.7 billion compared to the prior year. Approximately $2.7 billion of cash was used in investing activities during 2012. This amount included approximately $2.16 billion of cash paid as part of the CMO Acquisition and approximately $350.5 million in additions to property, plant, and equipment. It also includes $185.0 million of additional investment in our unconsolidated affiliate in the Marcellus Shale.
Financing Activities. Net cash provided by financing activities was $2.4 billion for the year ended December 31, 2012 compared to $600.3 million for the year ended December 31, 2011. This increase was primarily attributable to the proceeds from the issuance of debt and equity in 2012.
Sources of Liquidity. At December 31, 2012, our sources of liquidity included:
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cash on hand;
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cash generated from operations;
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borrowings under our revolving credit facility; and
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capital raised through debt and equity markets.
We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to fund our quarterly cash distributions to unitholders.
Credit Facility. On December 12, 2012, we amended our Amended and Restated Credit Agreement to, among other things, allow for the CMO Acquisition, increase our Consolidated Leverage Ratio covenant from 5.0 to 5.5, waive the Consolidated Leverage Ratio test for the fourth quarter 2012, allow the Partnership to enter into a secured bridge loan facility, and allow inclusion of Material Project EBITDA in the definition of Consolidated EBITDA. Additionally, for the three quarters following the CMO Acquisition, Consolidated EBITDA is measured as year-to-date EBITDA annualized.
On December 20, 2011, we exercised the accordion option feature under our Amended and Restated Credit Agreement to increase the total revolving commitments from $800 million to $1 billion. Additionally, we amended our Amended and Restated Credit Agreement to, among other things, permit us to make certain investments in Joint Ventures (as defined in the amendment), which Joint Ventures, unless otherwise agreed to by us, will not be subject to the provisions of the revolving credit facility and will not be required to become guarantors under the revolving credit facility. The amendment also provides that we may from time to time request increases in the total revolving commitments under the credit facility up to $1.25 billion, subject to the satisfaction of certain conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the facility. Our revolving credit facility matures in June 2016. As of December 31, 2012 we had no borrowings outstanding under our revolving credit facility.
Borrowings under our revolving credit facility are available to fund working capital, finance capital expenditures and acquisitions, provide for the issuance of letters of credit and for general partnership purposes. Our revolving credit facility is secured by all of our assets, and loans thereunder (other than swing line loans) bear interest at our option at either (i) the greater of (a) the reference rate of Wells Fargo Bank, NA, (b) the federal funds effective rate plus 0.50 percent or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (LIBOR), plus 1.00 percent, each of which is subject to a margin that varies from 0.625 percent to 1.50 percent per annum, according to the Partnership’s leverage ratio (as defined in the agreement), or (ii) the Eurodollar rate plus a margin that varies from 1.625 percent to 2.50 percent per annum, according to the Partnership’s leverage ratio. If we reach investment grade status, we will have the option to release the security under the credit facility and amounts borrowed will bear interest under a specified ratings-based pricing grid. The unused portion of the credit facility is subject to commitment fees of (a) 0.25 percent to 0.40 percent per annum while we are subject to the leverage-based pricing grid, according to the Partnership’s leverage ratio and (b) 0.20 percent to 0.35 percent per annum while we are subject to the ratings-based pricing grid, according to our senior unsecured long-term debt ratings.
Additionally, our revolving credit facility contains various covenants and restrictive provisions which limit our and our subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness. If we fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. Our revolving credit facility also has cross default provisions that apply to any other indebtedness we may have with an outstanding principal amount in excess of $15 million.
The revolving credit facility agreement contains certain negative covenants that (i) limit our ability, as well as the ability of certain of our subsidiaries, among other things, to enter into hedging arrangements and create liens and (ii) require us to maintain a consolidated leverage ratio, and an EBITDA to interest expense ratio, in each case as described in the credit facility agreement. The revolving credit facility agreement also provides for the discontinuance of the requirement for 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 we reach investment grade status. The revolving credit facility agreement 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, 2012.
Senior Notes. On December 19, 2012, we 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”). 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.
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.
On January 11, 2012, we and ACMP Finance Corp., a wholly owned subsidiary of Access MLP Operating, L.L.C., completed a private placement of $750.0 million in aggregate principal amount of 6.125 percent senior notes due 2022 (the “2022 Notes”). We used a portion of the net proceeds to repay all borrowings outstanding under our revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $12.4 million are being amortized over the life of the 2022 Notes.
The 2022 Notes will mature on July 15, 2022 and interest is payable on January 15 and July 15 of each year. We have the option to redeem all or a portion of the 2022 Notes at any time on or after January 15, 2017, at the redemption price specified in the indenture relating to the 2022 Notes, plus accrued and unpaid interest. We may also redeem the 2022 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to January 15, 2017. In addition, we may redeem up to 35 percent of the 2022 Notes prior to January 15, 2015 under certain circumstances with the net cash proceeds from certain equity offerings.
On April 19, 2011, we and 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 $7.8 million are being amortized over the life of the 2021 Notes.
The 2021 Notes will mature on April 15, 2021 and interest is payable on April 15 and October 15 of each year. We have the option to redeem all or a portion of the 2021 Notes at any time on or after April 15, 2015, at the redemption price specified in the indenture relating to the 2021 Notes, plus accrued and unpaid interest. We may also redeem the 2021 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to April 15, 2015. In addition, we may redeem up to 35 percent of the 2021 Notes prior to April 15, 2014 under certain circumstances with the net cash proceeds from certain equity offerings.
The 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 its subsidiaries; (2) pay distributions on, redeem or purchase our units, or redeem or purchase our subordinated debt; (3) make investments; (4) incur or guarantee additional indebtedness or issue preferred units; (5) create or incur certain liens; (6) enter into agreements that restrict distributions or other payments from certain subsidiaries to us; (7) consolidate, merge or transfer all or substantially all of our or certain of our subsidiaries’ assets; (8) engage in transactions with affiliates; and (9) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the 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 indenture, has occurred or is continuing, many of these covenants will terminate.
Equity Issuance. On December 18, 2012, we 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.
We 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. 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 2.0 percent interest in the Partnership 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:
•
maintenance capital expenditures, which include those expenditures required to maintain our long-term operating capacity and/or operating income and service capability of our assets, including the replacement of system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives, those expenditures necessary to remain in compliance with regulatory legal requirements or those expenditures necessary to complete additional well connections to maintain existing system volumes and related cash flows; or
•
expansion capital expenditures, which include those expenditures incurred in order to acquire additional assets to grow our business, expand and upgrade our systems and facilities, extend the useful lives of our assets, increase gathering, treating and compression throughput from current levels and reduce costs or increase revenues.
For the years ended December 31, 2012 and 2011, expansion capital expenditures totaled $659.7 million and $344.8 million, respectively. The 2012 amount includes $384.4 million of capital expenditures made as part of our unconsolidated affiliates that are accounted for as equity investments. The Maintenance capital expenditures totaled $75.2 million and $74.0 million for the years ended December 31, 2012 and 2011, respectively, an increase of 1.6 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, 2012 and 2011:
Contractual Obligations. At December 31, 2012, our contractual obligations included:
(1) Assumes a commitment fee of 0.40 percent on the unused portion of the credit facility.
(2) Includes our contractual obligations related to the CMO assets we acquired on December 20, 2012.
Application of Critical Accounting Policies
Readers of this report and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. The policies we consider to be the most significant are discussed below. The Partnership’s management has discussed each critical accounting policy with the Audit Committee of the Partnership’s general partner’s board of directors.
The selection and application of accounting policies are an important process that changes as our business changes and as accounting rules are developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment to the specific set of circumstances existing in our business.
Revenue and cost of sales recognition
We estimate certain revenue and expenses since actual amounts are not confirmed until after the financial closing process due to the standard settlement dates in the gas industry. We calculate estimated revenues using actual pricing and measured volumes. In the second month after production, we reverse the accrual and record the actual results. Prior to the settlement date, we record actual operating data to the extent available, such as actual operating and maintenance and other expenses. We do not expect actual results to differ materially from our estimates.
Depreciation and amortization
Depreciation associated with our property, plant and equipment and other assets is calculated using the straight-line method, based on the estimated useful lives of our assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, we and our predecessor make estimates with respect to useful lives and salvage values that we believe and our predecessor believes, respectively, are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation. The estimated service lives of our functional asset groups are as follows:
Intangible assets are generally amortized on a straight-line basis over their estimated useful lives, unless the assets’ economic benefits are consumed on an other than straight-line basis. The estimated useful life is the period over which the assets are expected to contribute directly or indirectly to the Partnership’s future cash flows.
Impairment of long-lived assets
Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount that the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risks associated with achieving the underlying cash flows.
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.
Recently Issued Accounting Standards
The Financial Accounting Standards Board (“FASB”) recently issued the following standard which we reviewed to determine the potential impact on our financial statements upon adoption.
On July 27, 2012, the FASB issued authoritative guidance related to the testing of indefinite-lived intangible assets for impairment. The guidance provides with the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more-likely-than-not that the indefinite-lived asset is impaired. If, after assessing the total events or circumstances, we determine that it is not more likely than not that the indefinite-lived asset is impaired, then we are not required to take further action. However, if we conclude otherwise, then we are required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount. The guidance also gives us the option to bypass the qualitative assessment for any period and proceed directly to performing the quantitative impairment test and resume performing the qualitative assessment in any subsequent period. This guidance will be effective for us beginning January 1, 2013 and will not have a material impact on our consolidated financial statements.
Forward-Looking Statements
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:
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our dependence on Chesapeake, Total, Mitsui, Anadarko Petroleum Corporation and Statoil for a majority of our revenues;
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the impact on our growth strategy and ability to increase cash distributions if producers do not increase the volume of natural gas they provide to our gathering systems;
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oil and natural gas realized prices;
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the termination of our gas gathering agreements;
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the availability, terms and effects of acquisitions;
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our potential inability to maintain existing distribution amounts or pay the minimum quarterly distribution to our unitholders;
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the limitations that our level of indebtedness may have on our financial flexibility;
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our ability to obtain new sources of natural gas, which is dependent on factors largely beyond our control;
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the availability of capital resources to fund capital expenditures and other contractual obligations, and our ability to access those resources through the debt or equity capital markets;
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competitive conditions;
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the unavailability of third-party pipelines interconnected to our gathering systems or the potential that the volumes we gather do not meet the quality requirement of such pipelines;
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new asset construction may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks;
•
our exposure to direct commodity price risk may increase in the future;
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our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;
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hazards and operational risks that may not be fully covered by insurance;
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our dependence on Chesapeake for substantially all of our compression capacity;
•
our lack of industry diversification; and
•
legislative or regulatory changes, including changes in environmental regulations, environmental risks, regulations by the Federal Energy Regulatory Commission and liability under federal and state environmental laws and regulations.
Other factors that could cause our actual results to differ from our projected results are described under the caption “Risk Factors” and 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.
ITEM 7A.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk
We are dependent on Chesapeake, Total and other producers for substantially all of our supply of natural gas volumes and are consequently subject to the risk of nonpayment or late payment by Chesapeake, Total or other producers of gathering, treating and compression fees. Chesapeake’s debt ratings for its senior notes are below investment grade, and they may remain below investment grade for the foreseeable future. Additionally, we are also subject to the risk that one or more of these customers default on its obligations under its gas gathering agreements with us. Not all of our counterparties under our gas gathering agreements are rated by credit rating agencies. Accordingly, this risk may be more difficult to evaluate than it would be with an investment grade or otherwise rated contract counterparty or with a more diversified group of customers, and unless and until we significantly increase our customer base, we expect to continue to be subject to significant and non-diversified risk of nonpayment or late payment of our fees.
Interest Rate Risk
Interest rates have recently experienced near record lows. If interest rates rise, our financing costs would increase accordingly. Although this could limit our ability to raise funds in the capital markets, we expect in this regard to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances. For the year ended December 31, 2012, a 125 basis point increase in the interest rate would have resulted in an $16.6 million decrease in net income.
Commodity Price Risk
We attempt to mitigate commodity price risk by contracting our operations on a long-term fixed-fee basis and through various provisions in our gas gathering agreements that are intended to support the stability of our cash flows. Natural gas prices are historically impacted by changes in the supply and demand of natural gas, as well as market uncertainty. However, an actual or anticipated prolonged reduction in natural gas prices or disparity in oil and natural gas pricing could result in reduced drilling in our areas of operations and, accordingly, in volumes of natural gas gathered by our systems. Notwithstanding 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.
ITEM 8.
ITEM 8. Financial Statements and Supplementary Data
ACCESS MIDSTREAM PARTNERS, L.P.
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
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 Rule 13a-15(f) under the Securities Exchange Act of 1934). Management has assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2012, utilizing the Committee of Sponsoring Organizations of the Treadway Commission’s Internal Control-Integrated Framework (COSO framework).
Based on this evaluation, management has determined the Partnership’s internal control over financial reporting was effective as of December 31, 2012.
The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2012 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.
/s/ J. MIKE STICE
J. Mike Stice
Chief Executive Officer
/s/ DAVID C. SHIELS
David C. Shiels
Chief Financial Officer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Partnership’s internal control over financial reporting based on our audits (which was an integrated audit in 2012 and 2011). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the 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.
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 has other significant transactions with affiliated entities.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
February 25, 2013
ACCESS MIDSTREAM PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of the consolidated financial statements.
ACCESS MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(1) Reflective of general and limited partner interest in net income attributable to Access Midstream Partners, L.P. since closing the Partnership’s IPO on August 3, 2010. See Note 4 to the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
ACCESS MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of the consolidated financial statements.
ACCESS MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Description of Business and Basis of Presentation
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, Maryland, New York, Ohio, Oklahoma, Pennsylvania, Texas, Virginia, West Virginia and Wyoming. The Partnership provides gathering, treating and compression services to Chesapeake Energy Corporation, Total Gas and Power North America, Inc., Statoil ASA, Anadarko Petroleum Corporation, Mitsui & Co., Ltd. and other producers under long-term, fixed-fee contracts.
For purposes of these financial statements, the “Partnership,” when used in a historical context, refers to the financial results of Chesapeake Midstream Partners, L.L.C. through the closing date of our initial public offering (“IPO”) on August 3, 2010 and to Access Midstream Partners, L.P. (NYSE: ACMP) and its subsidiaries thereafter. 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). “Chesapeake” refers to Chesapeake Energy Corporation (NYSE: CHK). “Total”, when discussing the upstream joint venture with Chesapeake, refers to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (NYSE: TOT, FP: FP), and when discussing our gas gathering agreement and related matters, refers to Total E&P USA, Inc. and Total Gas & Power North America, Inc., a wholly owned subsidiary of Total S.A.
The accompanying consolidated financial statements of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). To conform to these accounting principles, management makes estimates and assumptions that affect the amounts reported in the consolidated financial statements and the notes thereto. These estimates are evaluated on an ongoing basis, utilizing historical experience and other methods considered reasonable under the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates. Effects on the Partnership’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.
Offerings and acquisitions.
IPO. On August 3, 2010, the Partnership completed its initial public offering (“IPO”) of 24,437,500 common units (including 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option on August 3, 2010) at a price of $21.00 per unit. The Partnership’s common units are listed on the New York Stock Exchange (the “NYSE”) under the symbol “ACMP”.
The Partnership received gross offering proceeds in the IPO of approximately $513.2 million less approximately $38.6 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of the contribution agreement, the Partnership distributed the approximate $62.4 million of net proceeds from the exercise of the over-allotment option to the GIP I Entities on August 3, 2010. Upon completion of the IPO, Chesapeake and the GIP I Entities conveyed to the Partnership a 100 percent membership interest in Chesapeake MLP Operating, L.L.C., which owned all of its assets since September 2009.
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.
Haynesville Springridge acquisition. On December 21, 2010, the Partnership acquired the Springridge gathering system and related facilities from CMD for $500.0 million. The acquisition was financed with a draw on the Partnership’s revolving credit facility of approximately $234.0 million plus approximately $266.0 million of cash on hand. The Springridge gathering system is primarily located in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, the Partnership entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication, annual fee redetermination and a minimum volume commitment. These assets are referred to collectively as the “Springridge assets” and the acquisition is referred to as the “Springridge acquisition.”
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Marcellus acquisition. On December 29, 2011, the Partnership acquired from CMD, all of the issued and outstanding common units of Appalachia Midstream Services, L.L.C. (“Appalachia Midstream”) for total consideration 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 target in 2012 and no additional revenue related to the commitment was recognized. The target for 2013 represents the minimum amount of EBITDA we will recognize with the potential that throughput for these systems will generate EBITDA in excess of the guaranteed amounts.
CMO acquisition. 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, the Partnership now owns certain midstream assets in the Eagle Ford, Utica and Niobrara regions. The CMO Acquisition also extended our 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.
Equity Issuance. On December 18, 2012, we 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.
We 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. 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 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 our subordinated units and 50% 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 $1.8 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 our general partner and the GIP I Entities no longer have any ownership interest in us or our general partner.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Limited partner and general partner units. The following table summarizes common, subordinated, Class B, Class C and general partner units issued during the years ended December 31, 2012, 2011 and 2010:
Holdings of partnership equity. At December 31, 2012, the GIP II Entities held 1,933,244 notional general partner units representing a 1.0 percent general partner interest in the Partnership, 50 percent of the Partnership’s incentive distribution rights, 33,704,666 common units, 34,538,061 subordinated units, 5,929,025 Class B units and 5,599,634 Class C units. The GIP II Entities’ ownership represents an aggregate 41.3 percent limited partner interest in the Partnership. Williams held 1,933,244 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 subordinated units, 5,929,025 Class B units and 5,599,634 Class C units. Williams ownership represents an aggregate 23.8 percent limited partner interest in the Partnership. The public held 63,619,787 common units, representing a 32.9 percent limited partner interest in the Partnership.
2.
Summary of Significant Accounting Policies
Use of estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. Significant estimates include: (1) estimated useful lives of assets, which impacts depreciation and amortization; (2) accruals related to revenues, expenses and capital costs; (3) liability and contingency accruals; and (4) cost allocations as described in Note 5. Although management believes these estimates are reasonable, actual results could differ from the Partnership’s estimates.
Cash and cash equivalents. For purposes of the consolidated financial statements, investments in all highly liquid instruments with original maturities of three months or less at date of purchase are considered to be cash equivalents. The Partnership had approximately $65.0 million and $22.0 thousand of cash and cash equivalents as of December 31, 2012 and 2011, 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, 2012 and 2011, book overdrafts of $30.0 million and $8.5 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, 2012, the Partnership had no allowance for doubtful accounts. At December 31, 2011, the Partnership had an allowance for doubtful accounts of $0.4 million.
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.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Certain of the gathering systems of the Partnership are subject to an agreement with a subsidiary of Chesapeake that provides the Partnership rights and obligations equivalent to a capital lease. Under the terms of the agreement, the Partnership has rights to the associated capital assets for as long as the assets are in operation. Specifically, the Partnership will pay all costs associated with the related gathering systems, including all capital costs, operating costs and direct and indirect overhead costs. In exchange for paying such costs and for the services it provides pursuant to the agreement, the Partnership receives revenues derived from operation of the gathering systems. At December 31, 2012 and 2011, approximately $125.6 million and $124.5 million ($99.8 million and $105.0 million net of accumulated depreciation), respectively, of the Partnership’s gathering system assets were held under such agreement. Payments for capital costs under the agreement are made as the associated capital assets are constructed and, accordingly, as of December 31, 2012, the Partnership had no capital lease obligation liability associated with the assets held under the agreement.
Depreciation is calculated using the straight-line method, based on the assets’ estimated useful lives. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets.
Impairment of long-lived assets. Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount that the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risks associated with achieving the underlying cash flows.
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).
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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. The Partnership’s operations are organized into a single business segment, the assets of which consist of natural gas gathering systems, treating facilities, processing facilities, pipelines and related plant and equipment.
Revenue Recognition. In 2012, 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, 2012 and 2011.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Equity Based Compensation. Through December 31, 2012, certain employees of Chesapeake were seconded to the Partnership and provided operating, routine maintenance and other services with respect to the business under the direction, supervision and control of the Partnership’s general partner. A number of these employees received equity-based compensation through Chesapeake’s stock-based compensation programs, which consist of restricted stock issued to employees.
The fair value of the awards issued was determined based on the fair market value of the shares on the date of grant. However, the Partnership’s expense was allocated based on the lesser of the value at grant date or vest date. This value is amortized over the vesting period, which is generally four or five years from the date of grant. To the extent compensation cost relates to employee activities directly involved in gathering or treating operations, such amounts were charged to the Partnership and its predecessor and were reflected as operating expenses. Included in operating expenses is stock-based compensation of $9.0 million, $3.8 million and $2.1 million for the Partnership during the years ended December 31, 2012, 2011 and 2010, respectively. To the extent compensation cost relates to employees indirectly involved in gathering or treating operations, such amounts are charged to the Partnership and its predecessor through an overhead allocation and are reflected as general and administrative expenses.
The Access Midstream Long-Term Incentive Plan (“LTIP”) provides for an aggregate of 3,500,000 common units to be awarded to employees, directors and consultants of the Partnership’s general partner and its affiliates through various award types, including unit awards, restricted units, phantom units, unit options, unit appreciation rights and other unit-based awards. The LTIP has been designed to promote the interests of the Partnership and its unitholders by strengthening its ability to attract, retain and motivate qualified individuals to serve as employees, directors and consultants. As of December 31, 2012, there was $11.5 million of unrecognized compensation expense attributable to the LTIP, of which $10.7 million is expected to be recognized over a weighted average period of four years.
The following table summarizes LTIP award activity for the year ended December 31, 2012:
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. Amortization expense was $11.3 million and $11.3 million for the years ended December 31, 2012 and 2011, respectively, for the Partnership. No amortization expense was recognized for the year ended December 31, 2010.
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.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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.
3.
Partnership Distributions
The partnership agreement requires that, within 45 days subsequent to the end of each quarter, beginning with the quarter ended September 30, 2010, the Partnership 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, 2012 and 2011, the Partnership paid cash distributions to its unitholders of approximately $251.7 million and $200.9 million, respectively, representing the four distributions in 2012 and four distributions in 2011. See also Note 14-Subsequent Events concerning distributions approved in January 2013 for the quarter ended December 31, 2012.
Available cash. The amount of available cash (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter less the amount of cash reserves established by the Partnership’s general partner to provide for the proper conduct of its business, including reserves to fund future capital expenditures, to comply with applicable laws, or its debt instruments and other agreements, or to provide funds for distributions to its unitholders and to its general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement.
Minimum Quarterly Distribution. The partnership agreement provides that, during the subordination period, the common units are entitled to distributions of available cash each quarter in an amount equal to the minimum quarterly distribution, which is $0.3375 per common unit for a full fiscal quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Furthermore, arrearages do not apply to and therefore will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the subordination period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to or greater than the minimum quarterly distribution.
The subordination period will lapse at such time when the Partnership has earned and paid at least the quarterly minimum distribution per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2013. Also, if the Partnership has earned and paid at least 150 percent of the minimum quarterly distribution on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of removal. When the subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages. All subordinated units are held indirectly by affiliates of the Partnership’s general partner.
Class B Units
The Class B units are not entitled to cash distributions. Instead, prior to conversion into common units, the Class B units will receive quarterly distributions of additional paid-in-kind Class B units. The amount of each quarterly distribution per Class B unit will be 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
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
for the fiscal quarter ending December 31, 2014, each Class B unit will become convertible at the election of either the holder of such Class B unit or us 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 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 are entitled to quarterly cash distributions after the common units have received the minimum quarterly distribution, plus any arrearages from prior quarters. The Class C units will participate pro rata thereafter with all outstanding subordinated units until the subordinated units and Class C units receive the minimum quarterly distribution, after which the Class C units will participate in further cash distributions pro rata with our 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 will become convertible at the election of either the holder of such Class C unit or us into a common unit on a one-for-one basis. In the event of our liquidation, the holder of Class C units will be entitled to receive out of our assets available for distribution to the our partners the positive balance in each such holder’s capital account in respect of such Class C units, determined after allocating our net income or net loss among the Partners. All Class C units are 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.
General Partner Interest and Incentive Distribution Rights. The Partnership’s general partner is entitled to two percent of all quarterly distributions that the Partnership makes prior to its liquidation. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. The general partner’s initial two percent interest in the Partnership’s distributions may be reduced if the Partnership issues additional limited partner units in the future (other than the issuance of common units upon conversion of outstanding subordinated, Class B or Class C units or the issuance of common units upon a reset of the incentive distribution rights) and its general partner does not contribute a proportionate amount of capital to the Partnership to maintain its two percent general partner interest. After distributing amounts equal to the minimum quarterly distribution to common, subordinated and Class C 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.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
4.
Net Income per Limited Partner Unit
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):
(1) Adjusted to reflect amortization for the beneficial conversion feature.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
5.
Related Party Transactions
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, remained on our board of directors. Effective with the closing of the CMO Acquisition on December 20, 2012, the Partnership does not expect to complete additional significant transactions with Chesapeake. While Mr. Dell’Osso remains on our board, we no longer consider Chesapeake to be an affiliate of Access Midstream Partners. Because Chesapeake was our affiliate for a portion of 2012, we set forth below a description of our transactions with Chesapeake.
Affiliate transactions. In the normal course of business, natural gas gathering, treating and other midstream services are provided to Chesapeake and its affiliates. Revenues are derived almost exclusively from Chesapeake, which includes volumes attributable to third-party interest owners that participate in Chesapeake’s operated wells.
Omnibus Agreement. The Partnership has entered into an omnibus agreement with Access Midstream Ventures and Chesapeake Midstream Holdings that addresses 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 provide certain services including legal, accounting, treasury, human resources, information technology and administration. The employees supporting these operations are employees of Chesapeake Energy Marketing Inc. (“CEMI”) or Chesapeake. The consolidated financial statements for the Partnership and the predecessor include costs allocated from Chesapeake and CEMI for centralized general and administrative services, as well as depreciation of assets utilized by Chesapeake’s centralized general and administrative functions. Effective October 1, 2009, the Partnership was charged a general and administrative fee from Chesapeake based on the terms of the joint venture agreement. The established terms indicate corporate overhead costs are charged to the Partnership based on actual cost of the services provided, subject to a fee per Mcf cap based on volumes of natural gas gathered. The fee is calculated as the lesser of $0.0310/Mcf gathered or actual corporate overhead costs. General and administrative charges were $22.3 million, $23.7 million and $17.0 million for the years ended December 31, 2012, 2011 and 2010 for the Partnership.
Additional Services and Reimbursement. At the Partnership’s request, Chesapeake also provides the Partnership with certain additional services under the services agreement, including engineering, construction, procurement, business analysis, commercial, cartographic and other similar services to the extent they are not already provided by the seconded employees. In return for such additional services, the general partner reimburses Chesapeake on a monthly basis an amount equal to the time and materials actually spent in performing the additional services. The reimbursement for additional services is not subject to the general and administrative services reimbursement cap.
Chesapeake has agreed to perform all services under the relevant provisions of the services agreement using at least the same level of care, quality, timeliness and skill as it does for itself and its affiliates and with no less than the same degree of care, quality, timeliness and skill as its past practice in performing the services for itself and the Partnership’s business during the one year period prior to September 30, 2009. In any event, Chesapeake has agreed to perform such services using no less than a reasonable level of care in accordance with industry standards.
In connection with the services arrangement, the Partnership reimburses GIP for certain costs incurred by GIP in connection with assisting the Partnership in the operation of its business. For the years ended December 31, 2012 and 2011, the cost was $1.7 million and $0.6 million, respectively, for these support services.
Employee Secondment Agreement. Chesapeake, certain of its affiliates and the Partnership’s general partner have entered into an amended and restated employee secondment agreement pursuant to which specified employees of Chesapeake are seconded to the general partner to provide operating, routine maintenance and other services with respect to the Partnership’s business under the direction, supervision and control of the general partner. Additionally, all of the Partnership’s executive officers other than its chief executive officer, Mr. Stice, are seconded to the general partner pursuant to this agreement. The general partner, subject to specified exceptions and limitations, reimburses Chesapeake on a monthly basis for substantially all costs and expenses Chesapeake incurs relating to such seconded employees, including the cost of their salaries, bonuses and employee benefits, including 401(k), restricted stock grants and health insurance and certain severance benefits. Charges to the Partnership for the services rendered by such seconded employees were $49.4 million and $42.1 million for the years ended December 31, 2012 and 2011, respectively. These charges include $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.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The initial term of the employee secondment agreement extends through September 30, 2014. The term will automatically extend for additional twelve month periods unless any party provides 90 days’ prior written notice otherwise prior to the expiration of the initial term or the applicable twelve month period. The Partnership’s general partner may terminate the agreement at any time upon 90 days’ prior written notice.
Shared Services Agreement. In return for the services of Mr. Stice as the chief executive officer of the Partnership’s general partner, its general partner has entered into a shared services agreement with Chesapeake pursuant to which its general partner reimburses certain of the costs and expenses incurred by Chesapeake in connection with Mr. Stice’s employment. The general partner is generally expected, subject to certain exceptions, to reimburse Chesapeake for 50 percent of the costs and expenses of the amounts provided to Mr. Stice in his employment agreement; however, the ultimate reimbursement obligation is determined based on the amount of time Mr. Stice actually spends working for the Partnership. The reimbursement obligations of its general partner will continue for so long as Mr. Stice is employed by both the general partner and Chesapeake.
Gas Compressor Master Rental and Servicing Agreement. The Partnership has entered into a gas compressor master rental and servicing agreement with MidCon Compression, L.L.C., (“MidCon Compression”) a wholly owned indirect subsidiary of Chesapeake, pursuant to which MidCon Compression agreed to provide to the Partnership certain compression equipment that the Partnership uses to compress gas gathered on its gathering systems outside the Marcellus Shale and provide certain related services. In return for 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 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, $57.6 million and $47.8 million for the years ended December 31, 2012, 2011 and 2010, 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.
The compression agreement expires on September 30, 2019 but will continue from year to year thereafter, unless terminated by the Partnership no less than 60 days prior to the end of the term or any year thereafter. Additionally, either party may terminate in specified circumstances, including upon the other party’s failure to perform material obligations under the compression agreement if such failure is not cured within 60 days after notice thereof.
Inventory Purchase Agreement. Upon completion of the IPO, the Partnership entered into an inventory purchase agreement pursuant to which the Partnership agreed beginning as of September 30, 2009 to purchase from Chesapeake, in each case on terms and conditions to be mutually agreed upon by Chesapeake and the Partnership, its first $60.0 million of requirements of pipes that are useful in the conduct of the natural gas gathering, compression, dehydrating, treating and transportation business at a specified price per ton. For the years ended December 31, 2011 and 2010, the Partnership purchased approximately $23.4 million and $36.6 million, respectively, of inventory pursuant to this inventory purchase agreement and incorporated in the Partnership’s property, plant and equipment, thus satisfying the terms of this agreement.
Gas Gathering Agreements. The Partnership operates under gas gathering agreements that range from 10 to 20 years.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Future revenues under the Partnership’s gas gathering agreements will be derived pursuant to terms that will differ between the Partnership’s operating regions.
If one of the counterparties to the gas gathering agreements sells, transfers or otherwise disposes of to a third party properties within the Partnership’s acreage dedications, it does so subject to the terms of the gas gathering agreement, 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 agreement with the Partnership, subject to our consent. Our producer customers’ dedication of the gas produced from applicable properties under our gas gathering 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.
6.
Concentration of Credit Risk
Chesapeake and Total are the only customers from whom revenues exceeded 10 percent of consolidated revenues for the years ended December 31, 2012, 2011, and 2010, for the Partnership. The percentage of revenues from Chesapeake, Total and other customers are as follows:
(a) Revenues from Appalachia Midstream are accounted for as part of our equity method investment.
Financial instruments that potentially subject the Partnership and its predecessor to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. On December 31, 2012 and 2011, respectively, cash and cash equivalents were invested in a non-interest bearing account and money market funds with investment grade ratings.
7.
Property, Plant and Equipment
A summary of the historical cost of the Partnership’s property, plant and equipment is as follows:
Included in gathering systems is $455.4 million and $122.6 million at December 31, 2012 and 2011, respectively, that is not subject to depreciation as the systems were under construction and had not been put into service.
Depreciation expense was $153.8 million, $124.7 million and $88.6 million for the years ended December 31, 2012, 2011 and 2010, respectively, for the Partnership.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
8.
Business Combinations
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. 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 $207.9 million and is attributable to customer relationships acquired. This intangible asset will be 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 purchase price allocation is 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.
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 two-day period from closing of the acquisition on December 29, 2011, through December 31, 2011. The Partnership’s interest in the gas gathering systems is accounted for as an equity investment and is included in income from unconsolidated affiliate. For this period, income from unconsolidated affiliate attributable to Marcellus operations was $0.4 million. The purchase price in excess of the value underlying the gas gathering system assets and working capital is approximately $461.2 million and is attributable to customer relationships acquired. This intangible asset will be amortized over a 15 year period on a straight-line basis.
Haynesville Springridge. On December 21, 2010, the Partnership completed the Springridge acquisition for $500.0 million in cash that was funded with a draw on the Partnership’s revolving credit facility of approximately $234.0 million plus approximately $266.0 million of cash on hand. The Springridge gathering system is primarily located in Caddo and De Soto Parishes, Louisiana.
The results of operations presented and discussed in this annual report include results of operations from the Springridge gathering system for the 10-day period from closing of the acquisition on December 21, 2010, through December 31, 2010 and all of 2011 and 2012. The total purchase price of the Springridge acquisition was allocated as follows: gas gathering system assets of $327.5 million and a customer relationship with a value of $172.5 million. The useful life of the customer relationship acquired is estimated to be 15 years and is amortized on a straight-line basis.
The following table presents the pro forma condensed financial information of the Partnership as if the CMO Acquisition occurred on January 1, 2011, and as if the Springridge and Appalachia Midstream Acquisitions occurred on January 1, 2010. The pro forma adjustments reflected in the pro forma condensed consolidated financial statements are based upon currently available information and certain assumptions and estimates; therefore, the actual effects of these transactions will differ from the pro forma adjustments. However, the Partnership’s
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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, the Springridge assets and Appalachia Midstream to the Partnership.
9.
Unconsolidated Affiliates
At December 31, 2012 and 2011, the Partnership had the following investments:
Marcellus. On December 29, 2011, the Partnership acquired from CMD, a wholly owned subsidiary of Chesapeake, and certain of its affiliates, all of the issued and outstanding common units of Appalachia Midstream for approximately $879.3 million. Through the acquisition of Appalachia Midstream, the Partnership will operate 100 percent of and own an approximate average 47 percent interest in 10 gas gathering systems that consist of approximately 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. 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 and processing of natural gas and NGL in the Utica Shale play in Eastern Ohio. The infrastructure complex will consist of natural gas gathering and compression facilities constructed and operated by CMO, 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. The Partnership acquired UEOM as part of the CMO Acquisition in December 2012.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Ranch Westex JV, LLC. 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 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 will consist of the construction of two plants, a refrigeration plant and a cryogenic processing plant. The Partnership acquired Ranch Westex as part of the CMO Acquisition in December 2012.
Unconsolidated Affiliates Financial Information. The following tables sets forth summarized financial information of 100 percent of the 10 Marcellus gas gathering system investments in which the Partnership acquired an interest in December 2012 and 2011, as follows:
10.
Asset Retirement Obligations
The following table provides a summary of changes in asset retirement obligations, which are included in other liabilities in the accompanying consolidated balance sheets. Revisions in estimates for the periods presented relate primarily to revisions of current cost estimates, inflation rates and/or discount rates.
(1) Includes asset retirement obligation acquired as part the CMO Acquisition.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
11.
Long-Term Debt and Interest Expense
The following table presents the Partnership’s outstanding debt as of December 31, 2012 and 2011 (in thousands):
Revolving Bank Credit Facility. On August 2, 2010, June 10, 2011 and December 20, 2011 the Partnership amended its $500 million joint venture senior secured credit facility. These amendments extended the revolving credit facility’s maturity date and increased the revolving credit facility’s borrowing capacity, including the sub-limit for same-day swing line advances, as well as the revolving credit facility’s accordion feature that allowed the Partnership to increase the available borrowing capacity under the facility subject to the satisfaction of certain closing conditions.
On December 12, 2012, the Partnership further amended its senior secured revolving credit facility. The amended revolving credit facility matures in June 2016 and provides up to $1 billion of borrowing capacity, including a sub-limit of $50 million for same-day swing line advances and a sub-limit of $50 million for letters of credit. In addition, the revolving credit facility’s accordion feature allows the Partnership to increase the available borrowing capacity under the facility up to $1.25 billion, subject to the satisfaction of certain conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the revolving credit facility. As of December 31, 2012 the Partnership had no borrowings outstanding under its revolving credit facility.
Borrowings under the revolving credit facility are available to fund working capital, finance capital expenditures and acquisitions, provide for the issuance of letters of credit and for general partnership purposes. The revolving credit facility is secured by all of the Partnership’s assets, and loans thereunder (other than swing line loans) bear interest at the Partnership’s option at either (i) the greater of (a) the reference rate of Wells Fargo Bank, NA, (b) the federal funds effective rate plus 0.50 percent or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (LIBOR), plus 1.00 percent, each of which is subject to a margin that varies from 0.625 percent to 1.50 percent per annum, according to the Partnership’s leverage ratio (as defined in the agreement), or (ii) the Eurodollar rate plus a margin that varies from 1.625 percent to 2.50 percent per annum, according to the Partnership’s leverage ratio. If the Partnership reaches investment grade status, the Partnership will have the option to release the security under the credit facility and amounts borrowed will bear interest under a specified ratings-based pricing grid. The unused portion of the credit facility is subject to commitment fees of (a) 0.25 percent to 0.40 percent per annum while the Partnership is subject to the leverage-based pricing grid, according to the Partnership’s leverage ratio and (b) 0.20 percent to 0.35 percent per annum while the Partnership is subject to the ratings-based pricing grid, according to its senior unsecured long-term debt ratings.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Additionally, the revolving credit facility contains various covenants and restrictive provisions which limit the Partnership and its subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of the Partnership’s assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness. If the Partnership fails to perform its obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. The revolving credit facility also has cross default provisions that apply to any other indebtedness the Partnership may have with an outstanding principal amount in excess of $15 million.
The revolving credit facility agreement contains certain negative covenants that (i) limit the Partnership’s ability, as well as the ability of certain of its subsidiaries, among other things, to enter into hedging arrangements and create liens and (ii) require the Partnership to maintain a consolidated leverage ratio, and an EBITDA to interest expense ratio, in each case as described in the credit facility agreement. The revolving credit facility agreement also provides for the discontinuance of the requirement for the Partnership to maintain the EBITDA to interest expense ratio 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 we have released all collateral upon achieving investment grade status). The Partnership was in compliance with all covenants under the agreement at December 31, 2012.
Senior Notes. On April 19, 2011, the Partnership 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”). The Partnership used a portion of the net proceeds to repay borrowings outstanding under its revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $7.8 million are being amortized over the life of the 2021 Notes.
The 2021 Notes will mature on April 15, 2021 and interest is payable on the 2021 Notes on April 15 and October 15 of each year, beginning on October 15, 2011. The Partnership has the option to redeem all or a portion of the 2021 Notes at any time on or after April 15, 2015, at the redemption price specified in the indenture, plus accrued and unpaid interest. The Partnership may also redeem the 2021 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to April 15, 2015. In addition, the Partnership may redeem up to 35 percent of the 2021 Notes prior to April 15, 2014 under certain circumstances with the net cash proceeds from certain equity offerings.
On January 11, 2012, the Partnership and ACMP Finance Corp., a wholly owned subsidiary of Access MLP Operating, L.L.C., completed a private placement of $750.0 million in aggregate principal amount of 6.125 percent senior notes due 2022 (the “2022 Notes”). 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.
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.
In connection with the issuances and sales of the 2021 Notes and the 2022 Notes, we entered into registration rights agreements with the initial purchasers of the 2021 Notes and the 2022 Notes obligating us, among other things, to use our commercially reasonable best efforts to file exchange registration statements with the SEC so that holders of the 2021 Notes and the 2022 Notes could offer to exchange such notes for registered notes having substantially the same terms as the 2021 Notes and the 2022 Notes and evidencing the same indebtedness as the 2021 Notes and the 2022 Notes, respectively. On February 10, 2012, we filed an exchange offer registration statement for the 2021 Notes and the 2022 Notes with the SEC, which was were declared effective on March 14, 2012. The exchange offer was completed in April 2012, thereby fulfilling all of the requirements of the 2011 Notes and 2022 Notes registration rights agreements.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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”). 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.
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 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 operating company subsidiary, Access MLP Operating, L.L.C. Each of Access MLP Operating, L.L.C. and the Partnership’s other 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. Each guarantor is a 100 percent owned subsidiary of the Partnership. The guarantees registered under the registration statement are full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the Indenture. There are no significant restrictions on the ability of the Partnership or any guarantor to obtain funds from its subsidiaries by dividend or loan. None of the assets of the Partnership or a guarantor represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.
Capitalized Interest. Interest expense was net of capitalized interest of $14.6 million, $9.5 million, $2.6 million for the years ended December 31, 2012, 2011 and 2010, respectively, for the Partnership.
12.
Commitments and Contingencies
Environmental obligations. The Partnership is subject to various environmental-remediation and reclamation obligations arising from federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. Management believes there are currently no such matters that will have a material effect on the Partnership’s results of operations, cash flows or financial position and has not recorded any liability in these financial statements.
Litigation and legal proceedings. From time to time, the Partnership is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceedings for which a final disposition could have a material effect on the Partnership’s results of operations, cash flows or financial position. There was not an accrual for legal contingencies as of December 31, 2012 or 2011.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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 $81.1 million, $60.7 million, $50.1 million for the years ended December 31, 2012, 2011 and 2010, respectively, for the Partnership. The Partnership’s remaining contractual lease obligations as of December 31, 2012 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, 2012 are as follows:
(1) Includes the Partnership’s minimum rental payments for CMO acquired on December 20, 2012.
13.
Recently Issued Accounting Standards
The Financial Accounting Standards Board (“FASB”) recently issued the following standard which the Partnership reviewed to determine the potential impact on its financial statements upon adoption.
On July 27, 2012, the FASB issued authoritative guidance related to the testing of indefinite-lived intangible assets for impairment. The guidance provides with the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more-likely-than-not that the indefinite-lived asset is impaired. If, after assessing the total events or circumstances, we determine that it is not more likely than not that the indefinite-lived asset is impaired, then we are not required to take further action. However, if we conclude otherwise, then we are required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount. The guidance also gives us the option to bypass the qualitative assessment for any period and proceed directly to performing the quantitative impairment test and resume performing the qualitative assessment in any subsequent period. This guidance will be effective for us beginning January 1, 2013 and will not have a material impact on our consolidated financial statements.
14.
Subsequent Events
On January 25, 2013, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.45 per unit, or $84.1 million in aggregate. The cash distribution was paid on February 13, 2013 to unitholders of record at the close of business on February 6, 2013.
ACCESS MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
15.
Quarterly Financial Data (Unaudited)
Summarized unaudited quarterly financial data for 2012 and 2011 are as follows ($ in thousands except per share data):
(a) Total revenue less operating costs.
ITEM 9.
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
ITEM 9A.
ITEM 9A. Controls and Procedures
As required by Rules 13a-15(b) and 15d-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure. Based upon the evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures were effective at a reasonable level of assurance as of December 31, 2012.
Changes in Internal Control over Financial Reporting
No changes in the Partnership’s internal control over financial reporting occurred during the quarter ended December 31, 2012, that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
Management’s annual report on internal control over financial reporting and the audit report on our internal control over financial reporting of our independent registered public accounting firm are included in Item 8 of this report.
ITEM 9B.
ITEM 9B. Other Information
In our current report on Form 8-K filed on December 26, 2012, we described five gas gathering agreements and an operating agreement that we entered into in connection with the closing of the CMO Acquisition. We have determined that two of those gas gathering agreements meet the materiality standard for filing as exhibits to this annual report and, accordingly, we have filed those two gas gathering agreements as exhibits 10.9 and 10.10 to this annual report.
PART III
ITEM 10.
ITEM 10. Directors, Executive Officers and Corporate Governance
Management of the Partnership
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 12 directors: Alan S. Armstrong, Donald R. Chappel, James E. Scheel, Matthew C. Harris, William A. Woodburn, William J. Brilliant, J. Mike Stice, Robert S. Purgason, Dominic J. Dell’Osso, Jr., David A. Daberko, Philip L. Frederickson and Suedeen G. Kelly. Our general partner’s board of directors has affirmatively determined that David A. Daberko, 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 and a compensation committee.
The officers of our general partner manage and conduct our operations. In 2012, all of the executive officers of our general partner, other than J. Mike Stice, the Chief Executive Officer of our general partner, devoted all of their time to manage and conduct our operations. Mr. Stice allocated his time between managing our business and affairs and certain business and affairs of Chesapeake. Through December 31, 2012, Mr. Stice devoted approximately half of his time to our business. Since that date, Mr. Stice has devoted all of his time to the Partnership. Through December 31, 2012, the officers of our general partner and other Chesapeake employees operated our business and provided us with general and administrative services pursuant to the services agreement and the employee secondment agreement and, in the case of Mr. Stice, the shared services agreement, each as described in “Item 13. Certain Relationships and Related Transactions, and Director Independence-Agreements with Affiliates-Employee Secondment Agreement,” “-Services Agreement” and “-Shared Services Agreement.” 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 became employees of our general partner.
Directors and Executive Officers
The following table shows information regarding the current executive officers and directors of our general partner. Directors are appointed for a term of one year. The directors hold office until their successors have been duly elected and qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board of directors. There are no family relationships among any of our general partner’s directors or executive officers.
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.
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.
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.
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 L.P. (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 24% 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). 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.
Don 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 24% 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 WPZ and WMZ, the planned separation of its 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 in 2010 and serves on its audit committee and finance 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.
William J. Brilliant has served as a director of our general partner since June 2012. Mr. Brilliant is currently a Principal of GIP 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.
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.
Matthew C. Harris has served as a director of our general partner since January 2010. Mr. Harris is currently a partner of GIP leading GIP’s energy/waste industry investment team globally. He is a member of the board of GIP and of its Investment and Portfolio Valuation Committees. Prior to the formation of GIP in 2006, Mr. Harris was a Managing Director in the Investment Banking Department at Credit Suisse. Most recently, he was Co-Head of the Global Energy Group and Head of the EMEA Emerging Markets Group. Prior to 2003, Mr. Harris was a senior member of the Mergers and Acquisitions Group and served as Co-Head of Americas M&A. From 1984 to 1994, he was a senior member of the Mergers and Acquisitions Group of Kidder Peabody & Co. Incorporated. Mr. Harris is a director of the GIP portfolio companies Ruby Pipeline Holding Company LLC, East India Petroleum Limited and Transitgas. Mr. Harris graduated from the University of California at Los Angeles in 1984. We believe that Mr. Harris’ extensive energy industry background, particularly his expertise in mergers and acquisitions, brings important experience and skill to the board.
Suedeen G. Kelly has served as a director of our general partner since August 2010. Ms. Kelly has been a Partner in the law firm 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. She is a former Commissioner of the Federal Energy Regulatory Commission. Ms. Kelly was nominated by both Presidents Bush and Obama to three terms as Commissioner of the Federal Energy Regulatory Commission from 2003 to 2009. In 2000, she worked as Regulatory Counsel to the California Independent System Operator. In 1999, she was an aide to U.S. Senator Jeff Bingaman. She was a full-time professor at the University of New Mexico School of Law from 1986 to 1999, where she taught energy and public utility law. Before joining the faculty, she was Chair of the New Mexico Public Service Commission. Ms. Kelly has also been in the private practice of law with the Modrall Law Firm; Luebben, Hughes & Kelly; Ruckelshaus, Beveridge, Fairbanks & Diamond; and the Natural Resources Defense Council. Mrs. Kelly graduated from the University of Rochester in 1973 and from Cornell Law School in 1976. We believe that Ms. Kelly’s extensive energy industry background, particularly her expertise in federal and state regulatory matters, brings important experience and skill to the board.
James E. Scheel has served as a director of our general partner since December 2012. Mr. Scheel currently serves as senior vice president of corporate strategic development for Williams (NYSE: WMB) which owns approximately 24% of our limited partner interests and 50% of our general partner, where he is responsible for enterprise-level business development and customer relationship management. Additionally, he serves on the board of directors of Williams Partners L.P. (NYSE: WPZ). Before being appointed to his current role, he 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 earned his bachelor’s degree in petroleum engineering from the University of Tulsa in 1986. 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 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.
Board of Directors
Committees
Our general partner’s board of directors has three standing committees: the audit committee, conflicts committee and compensation committee.
Audit Committee. The audit committee consists of three independent members of our general partner’s board of directors, Messrs. Daberko and Frederickson and Ms. Kelly. Mr. Daberko is the current chairman of the audit committee. The members of the audit committee must meet the independence and experience standards established by the NYSE and the Exchange Act. The board has determined that each member of the audit committee is independent under the NYSE listing standards and the Exchange Act. The audit committee held eight meetings in 2012.
Mr. Daberko has been designated by our general partner’s board of directors as the “audit committee financial expert” meeting the requirements promulgated by the SEC based upon his education and employment experience as more fully detailed in Mr. Daberko’s biography set forth below.
The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and Partnership policies and controls. The audit committee has the sole authority to, among other things, (i) retain and terminate our independent registered public accounting firm, (ii) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm and (iii) establish policies and procedures for the pre-approval of all non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has been given unrestricted access to the audit committee and our management, as necessary.
Conflicts Committee. The conflicts committee consists of three independent members of our general partner’s board of directors, Messrs. Daberko and Frederickson and Ms. Kelly. Mr. Frederickson is the current chairman of the conflicts committee. The conflicts committee reviews specific matters that the board believes may involve conflicts of interest (including certain transactions with Chesapeake 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 Chesapeake, 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 12 meetings in 2012.
Compensation Committee. The compensation committee consists of three members of our general partner’s board of directors, Messrs. Harris and Woodburn and Ms. Kelly. Mr. Dell’Osso was replaced on the committee by Mr. Woodburn effective June 21, 2012. Ms. Kelly is the current chairman of the compensation committee. The objectives of the compensation committee are to develop an executive compensation system that is competitive with the Partnership’s peers and encourages both short-term and long-term performance in a manner beneficial to the Partnership and its operations. In fulfilling this objective, the compensation committee oversees compensation decisions for the officers of our general partner and administers 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 two meetings in 2012.
Director Qualifications
Evaluation of director candidates includes an assessment of whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct the affairs and business of the Partnership, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.
We have no minimum qualifications for director candidates. In general, however, we review and evaluate both incumbent and potential new directors in an effort to achieve diversity of skills and experience among our directors and in light of the following criteria:
•
experience in business, government, education, technology or public interests;
•
high-level managerial experience in large organizations;
•
breadth of knowledge regarding our business or industry;
•
specific skills, experience or expertise related to an area of importance to us, such as energy production, consumption, distribution or transportation, government, policy, finance or law;
•
moral character and integrity;
•
commitment to our unitholders’ interests;
•
ability to provide insights and practical wisdom based on experience and expertise;
•
ability to read and understand financial statements; and
•
ability to devote the time necessary to carry out the duties of a director, including attendance at meetings and consultation on Partnership matters.
Qualified candidates for nomination to the board are considered without regard to race, color, religion, gender, ancestry or national origin.
Board Leadership Structure and Role in Risk Oversight
Mr. Daberko currently serves as chairman of our general partner’s board of directors. Our general partner’s board of directors believes that no single organizational structure is best and most effective in all circumstances. Accordingly, the board retains the flexibility to determine the organizational structure that best enables the Partnership to confront the challenges and risks it faces. 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 Management Committee at periodic meetings and presented to the board’s risk management director to assess the impact on our strategic objectives and risk tolerance levels. Ms. Kelly currently serves as the board’s risk management director and updates the board on a quarterly basis regarding any risk management developments. In addition, the audit committee is responsible for overseeing the Partnership’s financial risks. A number of other processes at the board level support our risk management effort, including board reviews of our long-term strategic plans, capital budget and certain capital projects, interest rate hedging policy, significant acquisitions and divestitures, capital markets transactions and the delegation of authority to our management. Our Compensation Committee does not believe our compensation programs encourage excessive or inappropriate risk taking.
Meeting of Non-Management Directors and Communications with Directors
At each quarterly meeting of our general partner’s board of directors, all of the directors meet in an executive session without management participation. At least annually, our independent directors meet in an additional executive session without management participation or participation by non-independent directors. The chairman of the board of directors, Mr. Daberko, presides over all executive sessions.
Unitholders or interested parties may communicate with any and all members of our board, including our non-management directors, or any committee of our board, by transmitting correspondence by mail or facsimile addressed to one or more directors by name or to the chairman of the board or any committee of the board at the following address or fax number: Name of the Director(s), c/o 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) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our general partner’s board of directors and executive officers, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC, and any exchange or other system on which such securities are traded or quoted, initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by the SEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they file with the SEC.
To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations that no other reports were required, we believe that all reporting obligations of our general partner’s officers, directors and greater than 10 percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2012.
Code of Ethics, Corporate Governance Guidelines and Board Committee Charters
Our general partner has adopted a Code of Business Conduct and Ethics (the “Code of Ethics”) that applies to the directors, officers and employees of our general partner. If the general partner amends the Code of Ethics or grants a waiver, including an implicit waiver, from the Code of Ethics, we will disclose the information on our website. Our general partner has also adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance.
We make available free of charge, within the “Corporate Governance” subsection of the “Investors” section of our website at http://www.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 and compensation 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 (405) 935-7800. We will post on our website all waivers to or amendments of the Code of Ethics, which are required to be disclosed by applicable law and the NYSE’s Corporate Governance Listing Standards. The information contained on, or connected to, our website is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.
ITEM 11.
ITEM 11. Executive Compensation
Compensation Discussion and Analysis
Named Executive Officers
This Compensation Discussion and Analysis describes the compensation system for our named executive officers for 2012 consisting of the following individuals: (1) J. Mike Stice, Chief Executive Officer; (2) Robert S. Purgason, Chief Operating Officer; and (3) David C. Shiels, Chief Financial Officer.
Overview
Our general partner manages our operations and activities, and through its board of directors and officers, makes decisions on our behalf. However, during 2012, 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 during 2012. Our general partner’s reimbursement for certain compensation earned by the named executive officers is governed by, and subject to the limitations contained in, the services agreement, the employee secondment agreement and the shared services agreement. Please read “Certain Relationships and Related Party Transactions-Agreements with Affiliates-Shared Services Agreement.” The compensation expense allocated to us in 2012 with respect to Mr. Stice was 50 percent of his total compensation and with respect to Messrs. Shiels and Purgason was 100 percent of their total compensation. Such allocation with respect to Mr. Stice was calculated in accordance with the shared services agreement and based in part on Mr. Stice’s good faith estimate of the percentage of time he spent providing services to the Partnership. Accordingly, the compensation disclosed in this report as paid or awarded to Mr. Stice in 2012 reflects only the portion of compensation expense that is or will be payable by us pursuant to the terms of the shared services agreement.
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 became employees of our general partner.
Compensation Design and Process
Our compensation system was designed to:
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attract, retain and motivate executive officers with the competence, knowledge, leadership skills and experience to grow the Partnership’s profitability;
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align the interests of the executive officers with the interests of our unitholders by basing a significant majority of each executive officer’s total compensation on individual and Partnership performance; and
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encourage both a short-term and long-term focus, while discouraging excessive risk taking.
Through December 31, 2012, Chesapeake had employment agreements with our named executive officers, which are described below. The employment agreements are the primary basis for the 2012 compensation mix and levels for each of the named executive officers and reflect our comprehensive approach to executive compensation. In 2012, 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:
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
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 and Purgason 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. With respect to Mr. Stice, Chesapeake’s assessment of his performance also included consideration of his position as a Senior Vice President with Chesapeake and his role and relative contribution to Chesapeake; however, for purposes of this discussion we have focused on the portion of his compensation for which the Partnership has reimbursed Chesapeake.
Elements and Mix of Compensation
We provided short-term compensation in the form of base salaries and cash bonuses and long-term compensation in the form of equity awards and 401(k) matching contributions (paid in Chesapeake stock). Additionally, Chesapeake’s more highly-compensated employees, including the named executive officers, were eligible to defer certain compensation through a nonqualified deferred compensation program and to receive certain perquisites.
Cash Salary and Bonuses
The base salary levels of the named executive officers are intended to reflect each named executive officer’s base level of responsibility, leadership, tenure and contribution to the success and profitability of the organization. Base salaries tend to be less variable over time and are intended to contribute less to total compensation than incentive awards. Messrs. Stice, Purgason and Shiels base salary increased $150,000, $75,000 and $65,000, respectively, during 2012. Cash bonuses were intended to provide incentives based on a subjective performance assessment over a shorter period of time than the equity compensation listed below.
Equity-Based Compensation
The equity-based compensation of the named executive officers was intended to provide incentives for long-term performance that increases unitholder value by aligning the interests of the unitholders and the named executive officers. Equity awards were granted to the named executive officers in January and July as part of Chesapeake’s semi-annual review of employee compensation. Each of Messrs. Stice, Shiels and Purgason received phantom unit awards under our LTIP, which is described below under “Long-Term Incentive Plan”. Under the terms of the employee secondment agreement, Messrs. Shiels and Purgason were not eligible to receive Chesapeake restricted stock awards, and, instead, their interests in the MICP and phantom unit awards that were made under our
LTIP provided them with equity-related incentive compensation. Mr. Stice also received Chesapeake restricted stock awards. Under the shared services agreement concerning Mr. Stice, we were required to reimburse Chesapeake with respect to equity awards called for under the terms of Mr. Stice’s employment agreement but not any discretionary equity awards, unless agreed to by GIP.
Management Incentive Compensation Plan
Chesapeake Midstream Management, L.L.C. previously adopted, and in December 2012 our general partner assumed, the MICP, which provides incentive compensation awards, consisting of two components, to key members of management who have been designated as participants by our general partner. In connection with the assumption of the MICP, our general partner also amended and restated the MICP. 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. Pursuant to their respective 2012 MICP awards, Messrs. Stice, Purgason and Shiels were awarded the following percentages of each of the Excess Return Component and the Equity Uplift Component (each as defined below): 0.75% for Mr. Stice, 0.25% for Mr. Purgason and 0.125% for Mr. Shiels.
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.
Other Compensation Arrangements
Chesapeake also provided compensation in the form of personal benefits and perquisites to the named executive officers in 2012. Most of the benefits that Chesapeake provided to the named executive officers are the same benefits that are provided to all employees or large groups of senior-level employees of Chesapeake, including health and welfare insurance benefits, 401(k) benefits, which include matching contributions (up to 15 percent of an employee’s annual base salary and cash incentive bonus compensation), nonqualified deferred compensation arrangements and financial planning services. Chesapeake does not have a pension plan or any other retirement plan other than the 401(k) and nonqualified deferred compensation plans.
Employment Agreements
Messrs. Stice, Purgason and Shiels had employment agreements with Chesapeake through December 31, 2012, that governed 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.” Messrs. Stice, Shiels and Purgason executed new employment agreements with our general partner that were effective January 1, 2013. The employment agreement between the named executive officers and Chesapeake in effect during 2012 and the new employment agreements between the named executive officers and our general partner are each described below.
Chesapeake’s Agreement with J. Mike Stice
Mr. Stice’s employment agreement was amended and restated on November 10, 2011 and further amended December 22, 2011. His employment agreement had a three-year term expiring on November 10, 2014, but was terminated by Chesapeake on December 31, 2012. Pursuant to the shared services agreement, the compensation expense allocated to us in 2012 with respect to Mr. Stice was 50 percent of his total compensation.
In 2012, Mr. Stice was paid a base salary and granted cash and equity bonuses based on a subjective evaluation of the Partnership’s overall strong performance and his significant individual contributions to the Partnership’s and Chesapeake’s midstream achievements, including maintaining stable cash flows leading to distributions for 2012 equal to $1.71 per unit. We reimbursed Chesapeake for $375,000 related to the base salary Mr. Stice earned in 2012, $187,500 for cash bonuses earned by Mr. Stice in 2012 and $1,720,847 related to stock awards Mr. Stice earned in 2012, consisting of 71,267 shares of Chesapeake restricted stock.
Also in 2012, the board of directors of our general partner approved the payment of a one-time transaction bonus to Mr. Stice in connection with the CMO Acquisition (the “Transaction Bonus”). The Transaction Bonus consisted of a lump sum cash payment equal to $1.0 million that was paid in 2012. Mr. Stice was also granted an MICP award in 2012.
Our General Partner’s Agreement with J. Mike Stice
Mr. Stice’s new 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.
Chesapeake’s Agreements with David C. Shiels and Robert S. Purgason
Mr. Purgason serves as our general partner’s Chief Operating Officer and Mr. Shiels serves as our general partner’s Chief Financial Officer. Chesapeake’s employment agreements with Messrs. Shiels and Purgason were effective January 4, 2010 and December 1, 2009, respectively. The employment agreements each had a five-year term but were terminated by Chesapeake on December 31, 2012.
The agreements provided Messrs. Purgason and Shiels with an annual base salary for 2012 of $400,000 and $350,000, respectively. Additionally, the agreements specified target annual bonuses for Messrs. Purgason and Shiels in the following amounts, payable in cash: (i) $325,000 and $125,000, respectively, which were paid in full by January 31, 2012, and (ii) $350,000 and $150,000, respectively, payable not later than January 31, 2013, provided Messrs. Purgason and Shiels remained employed on the bonus dates. The agreements further provided that Messrs. Purgason and Shiels are each eligible to receive awards under our MICP.
In 2012, Messrs. Purgason and Shiels were granted bonuses consisting of cash and equity awards above their respective target bonus levels based on a subjective evaluation of the Partnership’s overall strong performance and their significant individual contributions to the Partnership’s achievements, including maintaining stable cash flows leading to distributions for 2012 equal to $1.71 per unit. Messrs. Purgason and Shiels earned cash bonuses of $551,850 and $200,750 respectively, and earned 8,895 and 7,090 Partnership phantom units with a grant date value of $250,000 and $200,000, respectively. In addition, Messrs. Purgason and Shiels received certain payments with respect to their participation interests for the Excess Return Component of the MICP awards granted in 2010. Mr. Purgason’s compensation levels are greater than Mr. Shiels in recognition of Mr. Purgason’s broad range of responsibilities and extensive industry experience.
Our General Partner’s Agreements with David C. Shiels and Robert S. Purgason
The new 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.
Compensation Committee Report
The Compensation Committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth above. Based on the review and discussion, the Committee recommended to the board of directors of 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, 2012.
Members of the Compensation Committee:
Suedeen G. Kelly, Chairman
Matthew C. Harris
William A. Woodburn
Long-Term Incentive Plan
General
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.
Restricted Units and Phantom Units
A restricted unit is a common unit that is subject to forfeiture during the restricted period. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of our general partner, cash equal to the fair market value of a common unit. The board of directors of our general partner may make grants of restricted units and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the board may determine are appropriate, including the period over which restricted or phantom units will vest. Our general partner may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement. Upon the vesting of phantom units, common units equal to the number of phantom units then vesting, or cash equal to the fair market value thereof, is delivered to the grantee, less the number of units or amount of cash equal to the income taxes payable on the vesting of the phantom units.
Distributions made by us with respect to awards of phantom units may, in the discretion of the board of directors of our general partner, be subject to the same vesting requirements as the restricted units. Our general partner, in its discretion, may also grant tandem distribution equivalent rights with respect to phantom units. Distribution equivalent rights are rights to receive an amount equal to all or a portion of the cash distributions made on units during the period a phantom unit remains “outstanding.” Restricted units and phantom units granted under the LTIP serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants do not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner receives remuneration for the units delivered with respect to these awards.
The board of directors of our general partner has approved and intends to continue to approve annual phantom unit grants to each of Messrs. Daberko and Frederickson and Ms. Kelly on the first business day of each calendar year and annually thereafter while the director serves as a member of our general partner’s board having an aggregate value to each director of approximately $50,000. The actual number of phantom units awarded under this grant will be determined by dividing $50,000 by the closing unit price per unit on the date of grant. The phantom units will vest one quarter immediately and on each of the first, second and third anniversary of the grant date (with vesting to be accelerated upon the grantee’s death or disability or the change of control of our general partner). On January 3, 2012, each of Messrs. Daberko and Frederickson and Ms. Kelly was awarded 1,712 phantom units.
Unit Options and Unit Appreciation Rights
The LTIP also permits the grant of options and unit appreciation rights covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units as determined by the board. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as our general partner may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price greater than or equal to the fair market value of a common unit on the date of grant.
Other Unit-Based Awards
The LTIP also permits the grant of other unit-based awards, which are awards that, in whole or in part, are valued or based on or related to the value of a unit. The vesting of any other unit-based award may be based on a participant’s length of service, the achievement of performance criteria or other measures. On vesting, any other unit-based award may be paid in cash and/or in units (including restricted units), as our general partner may determine.
Source of Common Units; Cost
Common units to be delivered with respect to awards may be newly issued units, common units acquired by our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner from any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring such common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash, our general partner will be entitled to reimbursement by us for the amount of the cash settlement. With respect to unit options and unit appreciation rights, our general partner will be entitled to reimbursement from us for the difference between the cost it incurs in acquiring these common units and the proceeds it receives from an optionee at the time of exercise of an option. Thus, we will bear the cost of the unit options.
Amendment or Termination of Long-Term Incentive Plan
The board of directors of our general partner, in its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the earlier of the 10th anniversary of the date it was initially adopted by our general partner or when common units are no longer available for delivery pursuant to awards under the LTIP. The board of directors of our general partner will also have the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP; provided, however, that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant, and/or result in taxation to the participant under Section 409A of the Internal Revenue Code (the “Code”).
Upon a change of control of us or our general partner, the board of directors of our general partner may, in its sole discretion:
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provide for either (A) the termination of any award in exchange for an amount of cash, if any, equal to the amount that would have been then attained upon the exercise or vesting of the award or (B) the replacement of the award with other rights or property;
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provide that the award be assumed by the successor or survivor entity or be exchanged for similar awards of the equity of the successor or survivor, with appropriate adjustments;
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make adjustments in the number and type of common units subject to, and terms and conditions and any performance criteria of, the award;
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provide that the award will be exercisable or payable, notwithstanding anything to the contrary in the LTIP or the award agreement; and
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provide that the award will be terminated upon such event.
Summary Compensation Table
The following table summarizes the compensation amounts for each of the named executive officers for the fiscal years ended December 31, 2012, 2011 and 2010.
(1) The amounts in this column reflect the base salary compensation earned by our named executive officers for the year indicated.
(2) The amounts in this column reflect bonuses earned by the named executive officers in the year indicated. For each of the named executive officers, the bonus amounts include bonuses provided for in their respective employment agreements and routine holiday bonuses.
(3) The amount shown in these columns reflect the aggregate grant date fair value of Chesapeake restricted stock awards granted to Mr. Stice and phantom unit awards granted to Messrs. Stice, Shiels and Purgason in the year indicated, determined in accordance with FASB ASC Topic 718. The value ultimately realized by the executives upon the actual vesting of the awards may or may not be equal to the grant date fair value. Refer to the Grants of Plan-Based Awards in 2012 table for additional information regarding restricted stock and phantom unit awards made to the named executive officers in the year ended December 31, 2012. More information about the named executive officers’ outstanding restricted stock and phantom units as of December 31, 2012 is provided in the Outstanding Equity Awards at Fiscal Year-End 2012 table. Unvested phantom units accrue distributions which are paid out upon the vesting of such units. Distribution equivalent rights are not reflected in the aggregate grant date fair value of phantom unit awards.
(4) The amounts shown in this column reflect amounts earned from awards made in December 2012 for Mr. Stice and awards made in December 2012 and January 2010 for Messrs. Purgason and Shiels pursuant to the Excess Return Component of the MICP. The amounts in this column will be paid pro-rata to the named executive officers over the remaining years of the MICP, subject to their continued employment with the partnership.
(5) Our named executive officers do not participate in a pension plan, and Chesapeake’s nonqualified deferred compensation plans did not provide for above-market or preferential earnings. See “Nonqualified Deferred Compensation for 2012” below for information regarding Chesapeake’s nonqualified deferred compensation plan.
(6) The amounts for Mr. Stice reflect compensation for his time spent providing services to the Partnership in the year indicated, which, in each case, was approximately 50 percent of his time with the exception of a $1.0 million bonus payment in December 2012 that was paid entirely by the Partnership.
(7) The dollar amounts for each perquisite and each other item of compensation shown in the “All Other Compensation” column and in this footnote represent our incremental cost of providing the perquisite or other benefit to the named executive officer. Amounts include the following perquisites and other items of compensation provided to our named executive officers in 2012.
(a) Amounts represent matching contributions made on behalf of the named executive officers under Chesapeake’s 401(k) plan.
(b) Amounts represent matching contributions made on behalf of the named executive officers under Chesapeake’s nonqualified deferred compensation plan.
(c) This column represents distribution equivalent rights credited to the named executive officers with respect to their phantom units.
(d) Amounts represent supplemental life insurance premiums paid on behalf of the named executive officers in 2012.
(e) Amounts represent supplemental accidental death and dismemberment insurance premiums paid on behalf of the named executive officers in 2012.
(f) Amounts represent the cost of financial advisory services provided to the named executive officers, other than Mr. Stice.
(g) Our employees and our named executive officers receive tickets to certain sporting events for which there is no incremental cost to the Company. This column represents the tax gross-up payments made to our named executive officers, other than Mr. Stice, with respect to such tickets during 2012.
Grants of Plan-Based Awards in 2012
The following table sets forth information concerning Chesapeake restricted stock and phantom units granted during 2012 to Mr. Stice in connection with his service to us, as well as phantom units granted to Messrs. Shiels and Purgason.
(1) Chesapeake approved the Chesapeake restricted stock awards to Mr. Stice in accordance with its regular procedures. Our general partner’s board of directors approved the phantom unit awards to the named executive officers at regularly scheduled meetings. Chesapeake’s and the general partner’s approval on December 15, 2011, and December 14, 2011, respectively, provided for the restricted stock and phantom unit grant dates to be the first trading day of January 2012. The general partner’s approval on June 20, 2012 provided for the restricted stock and phantom unit grant dates to be the first trading day of July 2012.
(2) Reflects estimated future payouts to Messrs. Stice, Purgason and Shiels, with regard to awards granted under the MICP in the fiscal year ended December 31, 2012, upon satisfaction of certain conditions. The MICP awards do not contain threshold or maximum payments and, therefore, the threshold and maximum values for the MICP awards have been excluded from the table in accordance with SEC Staff Guidance, Interpretation 220.02 (January 24, 2007).
(3) The restricted stock awards granted in 2012 vested upon Mr. Stice’s termination by Chesapeake on December 31, 2012, and phantom unit awards granted in 2012 vest ratably over four years from the grant date of the award. No dividends were accrued or paid on restricted stock awards until vested. Unvested phantom units accrue distributions that are paid out upon the vesting of such units.
(4) The amounts shown in this column represent the aggregate grant date fair value of the awards, determined in accordance with FASB ASC Topic 718. The values shown in reference to restricted stock awards are based on the closing price of Chesapeake’s common stock on the grant date. The values shown in reference to phantom unit awards are based on the closing price of the Partnership’s common units on the grant date. The value ultimately realized by the executive upon the actual vesting of the awards may or may not be equal to the grant date fair value. Unvested restricted stock does not accrue dividends. Unvested phantom units accrue distributions that are paid out upon the vesting of such units. Distribution equivalent rights are not reflected in the aggregate grant date fair value of phantom unit awards.
(5) Includes 10,595 shares of Chesapeake restricted stock and 21,853 phantom units granted to Mr. Stice in 2012.
(6) Messrs. Shiels and Purgason were granted only phantom units in 2012.
(7) The Excess Return Component is determined following the conclusion of each fiscal year in a five-year period beginning with 2012, based on the Partnership’s return on equity in the applicable fiscal year. Because the target amount is not determinable, the amounts in this column reflect the aggregate amount that Messrs. Stice, Purgason and Shiels would receive based on the assumption that the Partnership maintains its minimum quarterly distribution over the term of the award. The amounts owed to Messrs. Stice, Purgason and Shiels in each year under the Excess Return Component of the MICP will be paid to the executive in equal installments over the remaining years of the five year period of the award.
(8) The Equity Uplift Component is a long-term award that is payable five years from the date of the award based on the Partnership’s common unit price performance over that period. Because the target amount is not determinable, the amounts in this column reflect the amount that would be payable to Messrs. Stice, Purgason and Shiels if the award determination date was December 31, 2012. In that case, the award amount would be determined by calculating the Partnership’s average closing price for its common units over a trailing 30 day period and applying Messrs. Stice, Purgason and Shiels percentage interest in any appreciation of such price over the Partnership’s base unit price.
Outstanding Equity Awards at Fiscal Year-End 2012
The following table reflects outstanding phantom unit awards as of December 31, 2012, for each of the named executive officers in connection with their service to the Partnership.
(1) By their terms, the phantom unit awards vest ratably over four years from the grant date of the award.
(2) The value shown for phantom unit awards is based on the closing price of the Partnership’s common units on the NYSE on December 31, 2012, of $33.54 per unit.
Stock Vested and Units Vested in 2012
The following table reflects Chesapeake restricted stock awards that vested in 2012. The dollar amounts and number of securities included in the table below reflect an allocation based upon the time allocation for Mr. Stice previously discussed.
(1) The number of shares acquired on vesting reflects the vesting of Chesapeake restricted stock awards granted to Mr. Stice in connection with his service to the Partnership. The value realized on vesting is based on the closing price of Chesapeake’s common stock on the vesting dates.
The following table reflects phantom unit awards that vested in 2012. The dollar amounts and number of securities included in the table below reflect an allocation based upon the time allocation for Mr. Stice previously discussed.
(1) The number of units acquired on vesting reflects the vesting of phantom unit awards granted to the applicable named executive officer in connection with his service to the Partnership. The value realized on vesting is based on the closing price of the Partnership’s common units on the vesting dates.
Nonqualified Deferred Compensation for 2012
(1) Executive contributions are included as compensation in the Salary and Bonus columns, as applicable, of the Summary Compensation Table.
(2) Company matching contributions are included as compensation in the All Other Compensation column of the Summary Compensation Table.
The named executive officers were permitted to participate in the Chesapeake Amended and Restated Deferred Compensation Plan (the “DCP”), a nonqualified deferred compensation plan. The DCP allowed certain employees to voluntarily defer receipt of a portion of their salary and/or their annual bonus payments. Pursuant to the terms of the employee secondment agreement and, in the case of Mr. Stice, the shared services agreement, a portion of the expense related to these plans was allocated to us by Chesapeake.
Potential Payments Upon Termination or Change of Control
As discussed under “Compensation Discussion and Analysis” above, Chesapeake had employment agreements through December 31, 2012 with each of the named executive officers, that governed 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 Chesapeake’s 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 through December 31, 2012.
J. Mike Stice Employment Agreement. Mr. Stice’s employment agreement provided for certain change of control and termination benefits in the event of a change of control or a termination of Mr. Stice’s employment under certain circumstances. If a change of control (as defined below) occurred during the term of the agreement, Mr. Stice would receive a lump sum payment within 30 days of the effective date of the change of control, equal to 200 percent of the sum of Mr. Stice’s then-current annual base salary and the actual bonuses paid to Mr. Stice during the twelve-month period preceding the change of control. Additionally, all equity compensation granted under the employment agreement would vest in full.
Upon written notice, Mr. Stice’s employment could have been terminated by either party to his agreement for any reason. Generally, upon any termination, Mr. Stice would have been entitled to receive only accrued but unpaid paid time off (“PTO”) through the termination date. If Mr. Stice’s employment was terminated without cause (as defined below), he would also have been entitled to receive a lump sum payment equal to 52 weeks of base salary and all equity compensation granted under the employment agreement as well as his supplemental matching contributions under the DCP would have vested in full upon termination.
The employment agreement included the opportunity that in the event of Mr. Stice’s retirement following the attainment of at least age 55, Mr. Stice would have been eligible to receive accelerated vesting, in whole or in part, of (i) his supplemental matching contributions under the DCP and (ii) all equity compensation granted under the employment agreement (other than any equity compensation granted under the 2006 Long Term Stock Incentive Program). If Mr. Stice had died, his beneficiary or estate would have been entitled to (i) receive a lump sum payment equal to 52 weeks of base salary, (ii) vesting in full of all equity compensation granted under the employment agreement as well as his supplemental matching contributions under the DCP and (iii) receive payment of any PTO amounts accrued through the termination date.
If Mr. Stice had been terminated due to a disability (as defined below), he would have been entitled to (i) receive a lump sum payment equal to 26 weeks of base salary (reduced by any benefits payable under any disability plans provided by the Company), (ii) vesting in full of all equity compensation granted under the employment agreement as well as his supplemental matching contributions under the DCP and (iii) receive payment of any PTO amounts accrued through the termination date.
All severance payments due upon Mr. Stice’s termination without cause or due to his disability would have been made within 30 days of the termination date (90 days, in the case of death), unless Mr. Stice constituted a “specified employee” within the meaning of Section 409A of the Code, in which case payments subject to Section 409A of the Code would have been delayed for six months following the termination date. All severance payments and benefits would have been contingent on Mr. Stice (or, in the event of his death, his beneficiary or the administrator of his estate) executing (and not revoking) a severance and release agreement within 45 days of the termination, and complying with the restrictive covenants described below.
Mr. Stice’s agreement contained certain confidentiality, noncompete, and nonsolicitation covenants. Specifically, Mr. Stice agreed not to disclose any confidential information during the term of his employment and for three years following his termination. In addition, Mr. Stice agreed to a noncompete covenant for six months following his termination and not to solicit customers or employees for a period of one year following his termination.
A “change of control” was generally defined in Mr. Stice’s employment agreement as the occurrence of one of the following: (a) the acquisition by a group of 30 percent or more of the outstanding shares of Chesapeake common stock or the combined voting power of the then outstanding Chesapeake securities (other than acquisitions by or from Chesapeake, by a Chesapeake employee benefit plan, in a transaction sponsored by Aubrey K. McClendon, or by an entity described in the remaining subsections of this definition); (b) the individuals on the Chesapeake board of directors as of June 11, 2010, cease to constitute at least a majority of that board; (c) the consummation of a reorganization, merger, consolidation or sale of all or substantially all of the assets of Chesapeake; or (d) the approval by the Chesapeake shareholders of a complete liquidation or dissolution. “Cause” was defined in the agreement as Mr. Stice’s breach or threatened breach of his agreement, his neglect of or failure to perform his duties, his misappropriation, fraudulent conduct or dishonesty with respect to company business, or his personal misconduct which injures Chesapeake and/or reflects poorly on Chesapeake’s reputation. A termination without cause included a termination by Mr. Stice due to Chesapeake’s elimination of Mr. Stice’s position, a reduction in duties and/or reassignment of Mr. Stice to a new position of less authority, or a reduction to his base salary, provided that Mr. Stice provided Chesapeake with 90 days’ advance notice prior to termination and Chesapeake had 30 days from the date of such notice to cure such event or condition (to the extent curable). Mr. Stice would have been considered incapacitated, or disabled, under his employment agreement if he suffered from a physical or mental condition which, in the reasonable judgment of Chesapeake’s management, prevented Mr. Stice from performing his duties for a period of at least three consecutive months.
Mr. Stice’s termination and change of control benefits were provided to him in connection with the services that he provided to Chesapeake, and the Partnership was not required to reimburse Chesapeake for any such benefits.
David C. Shiels and Robert S. Purgason Employment Agreements. Mr. Shiels’ and Mr. Purgason’s employment agreements with Chesapeake provided for certain termination benefits in the event of termination under certain specified circumstances. Upon written notice, Mr. Shiels’ or Mr. Purgason’s employment could have been terminated by either party to the agreement for any reason. Generally, upon any termination, each of Messrs. Shiels and Purgason would have been entitled to receive only accrued but unpaid vacation through the termination date.
If employment had been terminated without cause (similarly defined as the term “cause” in Mr. Stice’s agreement described above), Mr. Purgason would have been entitled to a lump sum payment equal to one year’s worth of base salary and Mr. Shiels would have been entitled to a lump sum payment equal to 26 weeks of base salary. If the termination without cause occurred within two years following the occurrence of a change of control (as defined in the employment agreement), each of Messrs. Shiels and Purgason would also have been entitled to receive, in addition to the base salary amounts described in the preceding sentence, an amount equal to the actual bonuses (excluding signing bonuses) paid to him during the 12 calendar months preceding the change of control.
If either Mr. Shiels or Mr. Purgason had been terminated due to a disability (similarly defined as the terms “incapacitated” and “disabled” in Mr. Stice’s agreement described above), he would have been entitled to a lump sum payment equal to 26 weeks of base salary, reduced by any benefits payable under any employer-sponsored disability plan. If either Mr. Shiels or Mr. Purgason had died, his beneficiary or estate would have been entitled to receive a lump sum payment equal to 52 weeks of his base salary.
All severance payments due upon the termination of Messrs. Shiels and Purgason would have been made within 30 days of the termination date (90 days, in the case of death), unless the executive constituted a “specified employee” within the meaning of Section 409A of the Code, in which case payments subject to Section 409A would have been delayed until the earlier of the executive’s death or six months following the termination date. Such payments would have been contingent on the executive (or, in the event of his death, his beneficiary or the administrator of his estate) executing (and not revoking) a severance and release agreement within 30 days of the termination (90 days, in the case of death), and complying with the restrictive covenants described below.
The employment agreements with Messrs. Shiels and Purgason contained certain confidentiality, noncompete, and nonsolicitation covenants. Specifically, each of Messrs. Shiels and Purgason agreed not to disclose any confidential information at any time either during or following the term of his employment. In addition, Messrs. Shiels and Purgason agreed to a noncompete covenant for 26 weeks and one year, respectively, following termination and not to solicit customers or employees for a period of one year following termination. Termination of either Mr. Shiels’ or Mr. Purgason’s employment due to the violation of one of these covenants would have constituted a termination for cause.
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, the full amount of the participant’s Equity Uplift Component (if any) (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. Shiels and Purgason under each the above described arrangements if such termination events had been triggered as of December 31, 2012.
(1) Amounts based on the closing price of the Partnership’s common units on December 31, 2012.
(2) Includes acceleration of both Excess Return Component and Equity Uplift Component. Estimated amounts that would have been payable under the Equity Uplift Component, on December 31, 2012, based upon the assumption that the Partnership’s common units would be valued at $33.73, the average closing price for the units over a trailing 30-day period.
(1) Amounts based on the closing price of the partnership’s common units on December 31, 2012.
(2) Includes acceleration of both Excess Return Component and Equity Uplift Component. Estimated amounts that would have been payable under the Equity Uplift Component, on December 31, 2012, based upon the assumption that the Partnership’s common units would be valued at $33.73, the average closing price for the units over a trailing 30-day period.
Compensation of Directors
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.
The following table sets forth the compensation earned by the directors of our general partner in 2012:
(1) Reflects the aggregate grant date fair value of 2012 unit awards computed in accordance with FASB ASC Topic 718. Messrs. Daberko and Frederickson and Ms. Kelly were each awarded 1,456 common units on January 3, 2013, 364 of which were immediately vested and the remainder of which were phantom units that vest one-third on each of the first, second and third anniversary of the date of grant. As of December 31, 2012, each of Messrs. Daberko and Frederickson and Ms. Kelly held 2,158 unvested phantom units.
(2) The amounts shown in this column reflect distribution equivalent rights with regard to phantom unit awards that were accrued and credited to the directors in 2012.
(3) Mr. McClendon resigned effective June 15, 2012, and Mr. Brilliant became a director on such date.
(4) Messrs. Purgason and Stice became directors on July 24, 2012 and June 29, 2012.
(5) Messrs. Armstrong, Chappel and Scheel became directors on December 20, 2012.
Compensation Committee Participation
In 2012, Ms. Kelly and Messrs. Dell’Osso, Harris, and Woodburn served on the compensation committee of our general partner’s board of directors. Mr. Dell’Osso was replaced on the committee by Mr. Woodburn effective June 21, 2012.
Relation of Compensation Policies and Practices to Risk Management
We expect our compensation arrangements to contain a number of design elements that serve to minimize the incentive for taking excessive or inappropriate risk to achieve short-term, unsustainable results. In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us. Please read “-Compensation Discussion and Analysis.”
ITEM 12.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following tables set forth the beneficial ownership of our common units and other classes of equity that, unless otherwise noted, as of February 12, 2013, are held by:
•
each member of our general partner’s board of directors;
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each named executive officer of our general partner;
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all directors and officers of our general partner as a group; and
•
each person or group of persons known by us to be a beneficial owner of 5 percent or more of the then outstanding units.
Ownership of Our Common Units
* Less than 1.0 percent
(1) Unless otherwise indicated, the address for all beneficial owners in this table is 525 Central Park Drive, Oklahoma City, Oklahoma 73105.
(2) Based on 97,373,334 common units outstanding.
(3) This information is as of February 6, 2013, as reported in a Schedule 13D/A filed jointly by Global Infrastructure Investors II, LLC, a Delaware limited liability company (“Global Investors”), Global Infrastructure GP II, L.P., a Guernsey limited partnership (“Global GP”), GIP II Eagle Acquisition Holdings GP, LLC, a Delaware limited liability company (“Eagle GP”), GIP II Eagle Holdings Partnership, L.P., a Delaware limited partnership (“Eagle Holdings”), GIP II Hawk Holdings Partnership GP, LLC, a Delaware limited liability company (“Hawk GP”), GIP II Hawk Holdings Partnership, L.P., a Delaware limited partnership (“GIP II-Hawk”), GIP II Eagle 2 Holding, L.P., a Delaware limited partnership (“GIP Eagle 2”) and GIP II Hawk 2 Holding, L.P., a Delaware limited partnership (“GIP Hawk 2”) on February 6, 2013. Eagle GP is the general partner of Eagle Holdings, and Hawk GP is the general partner of GIP II-Hawk. Global GP is the managing member of each of Eagle GP and Hawk GP and is the general partner of the managing member of the general partner of each of GIP Eagle 2 and GIP Hawk 2. Global Investors is the sole general partner of Global GP. Eagle Holdings, GIP II-Hawk, GIP Eagle 2 and GIP Hawk 2 hold the following interests in us:
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Eagle Holdings owns 33,147,835 common units and 33,967,461 subordinated units and a 50 percent membership interest in Access Midstream Ventures;
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GIP II-Hawk owns 5,649,160 Class B units and 5,335,317 Class C units;
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GIP Eagle 2 owns 556,831 common units and 570,600 subordinated units;
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GIP Hawk 2 owns 279,865 Class B units and 264,317 Class C units.
Matthew C. Harris and William A. Woodburn, two of the directors of our general partner, as members of internal committees of the GIP II Entities, are entitled to vote on decisions to vote, or to direct to vote, and to dispose, or to direct the disposition of, the common units held by the GIP II Entities but cannot individually or together control the outcome of such decisions. Each of the GIP II Entities disclaims beneficial ownership of the common units held by it except to the extent of its respective pecuniary interest in such units. Each of Matthew C. Harris and William A. Woodburn disclaims any beneficial ownership of the common units held by the GIP II Entities.
(4) This information is as of December 28, 2012, as reported in a Schedule 13D filed by The Williams Companies, Inc. Williams is the owner of 50 percent of the membership interests of Access Midstream Ventures and the owner of 34,538,061 subordinated units, 5,929,025 Class B units and 5,599,634 Class C units. Alan S. Armstrong, Don R. Chappel and James E. Scheel, three of the directors of our general partner, as executive officers of Williams, do not have any beneficial ownership of the common units held by Williams.
(5) This information is as of December 31, 2012, as reported in a Schedule 13G filed by Tortoise Capital Advisors, L.L.C., an investment adviser to certain investment companies registered under the Investment Company Act of 1940, on February 12, 2013. The Schedule 13G reports (i) shared power to vote or direct the vote of 7,689,775 common units and (ii) shared power to dispose or direct the disposition of 8,295,044 common units. Tortoise Capital Advisors, L.L.C. may be deemed the beneficial owner of the securities covered by the Schedule 13G. Tortoise Capital Advisors, L.L.C. disclaims any beneficial interest in the securities reported on Schedule 13G.
(6) This information is as of December 31, 2012, as reported in a Schedule 13G filed by ClearBridge Investments, LLC, an investment advisor to certain investment companies registered under the Investment Company Act of 1940, on February 14, 2013. The Schedule 13G reports (i) shared power to vote or direct the vote of 5,680,420 common units and (ii) shared power to dispose or direct the disposition of 5,680,420 common units.
(7) This information is as of December 31, 2012, as reported in a Schedule 13G filed by Goldman Sachs Asset Management, an investment advisor in accordance with Rule 13d-1 (b) (1) (ii) (E), on February 14, 2013. The Schedule 13G reports (i) shared power to vote or direct the vote of 5,202,494 common units and (ii) shared power to dispose or direct the disposition of 5,202,494 common units.
Ownership of Subordinated Units
(1) Based on 69,076,122 subordinated units outstanding.
Ownership of Class B Units
(1) Based on 11,858,050 Class B units outstanding.
Ownership of Class C Units
(1) Based on 11,199,268 Class C units outstanding.
Securities authorized for issuance under equity compensation plan
The following table sets forth information with respect to the securities that may be issued under the LTIP as of December 31, 2012. For more information regarding the LTIP, which did not require approval by our unitholders, please see “Item 11. Executive Compensation-Long-Term Incentive Plan.”
(1) The board of directors of our general partner adopted the LTIP in 2010.
ITEM 13.
ITEM 13. Certain Relationships and Related Transactions, and Director Independence
At February 12, 2013, the GIP II Entities owned 33,704,666 common units, 34,538,061 subordinated units, 5,929,025 Class B units and 5,599,634 Class C units, representing an aggregate 41.3 percent limited partner interest in us, and Williams owned 34,538,061 subordinated units, 5,929,025 Class B units and 5,599,634 Class C units representing an aggregate 23.8 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.
Distributions and Payments to Our General Partner and Its Affiliates
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.
Operational Stage
Distributions of available cash to our general partner and its affiliates
We generally make cash distributions 98.0 percent to our unitholders pro rata, including the GIP II Entities and Williams as the holders of an aggregate 33,704,666 common units, 69,076,122 subordinated units and 11,119,268 Class C units and 2.0 percent to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0 percent interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner is entitled to increasing percentages of the distributions, up to 50.0 percent of the distributions above the highest target distribution level.
If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and to maintain its general partner interest.
Payments to our general partner and its affiliates
In June 2012, Chesapeake sold its ownership interest in our general partner to the GIP II Entities; however we are including the following disclosure because of Chesapeake’s ownership through that date. Our general partner does not receive a management fee or other compensation for the management of our partnership. Prior to making distributions, we reimburse Chesapeake for its provision of certain general and administrative services and any additional services we may request from Chesapeake each pursuant to the services agreement; the costs and expenses of employees seconded to us pursuant to the employee secondment agreement; and certain costs and expenses incurred in connection with the services of Mr. Stice as the chief executive officer of our general partner pursuant to the shared services agreement. Other than the volumetric cap on general and administrative expenses included in the services agreement, our reimbursement obligations are uncapped. In addition, we reimburse our general partner and its affiliates for all expenses they incur on our behalf. Under our partnership agreement, our general partner determines in good faith the amount of these expenses.
Withdrawal or removal of our general partner
If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
Liquidation
Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.
Related-Party Transactions
In June 2012, Chesapeake sold all of its ownership interests in us and in our general partner; however, Mr. Dell’Osso remained on our board of directors. We set forth below a description of our transactions with Chesapeake entered into in 2012.
Operating Agreement
On December 20, 2012, Access MLP Operating, LLC, our operating subsidiary, entered into an Operating Agreement with Mid-America Midstream Gas Services, LLC, a subsidiary of Chesapeake (“Mid-America”) whereby Access MLP Operating, LLC will provide management and operational activities for Mid-America with respect to certain gas gathering systems in return for a management fee. The operating agreement expires on March 31, 2013.
Non-Solicitation Agreement
In connection with the CMO Acquisition, on December 20, 2012, we, Chesapeake and certain of our affiliates entered into a non-solicitation agreement whereby for two years neither we nor our affiliates will actively solicit, from working interest owners in Chesapeake-operated wells located in our dedication areas, the purchase of gas produced from such wells. The remedy for violation of the non-solicitation agreement is injunctive relief requiring specific performance by the breaching party pursuant to the terms of the agreement.
Termination Agreement
On December 20, 2012, we entered into a termination agreement with a number of parties including CMD, whereby we terminated certain provisions of the omnibus agreement entered into between us and affiliates of Chesapeake at the time of our initial public offering, including our right of first offer with respect to (i) opportunities to develop or invest in midstream energy projects within five miles of our acreage dedications in the Barnett Shale and Mid-Continent regions, (ii) opportunities to succeed third parties in expiring midstream energy service contracts within the acreage dedications and within five miles thereof in the Barnett Shale and Mid-Continent regions and (iii) opportunities with respect to future midstream divestitures outside of the acreage dedications. In addition, we also terminated our marketing and noncompete agreements with affiliates of Chesapeake in the Barnett Shale, Mid-Continent, Haynesville Shale and Marcellus Shale regions.
Transition Services Agreements
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 the Partnership (the “GIP II Acquisition”), we entered into a letter agreement with Chesapeake regarding the terms on which Chesapeake would provide certain transition services to the Partnership and our general partner following the GIP II Acquisition. Among other things, the letter agreement provided for the continuation of our services agreement and secondment agreement with Chesapeake until December 31, 2013. In addition, the letter agreement reduced the termination date of our trademark license agreement with Chesapeake to December 31, 2012. 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 and altering the workers’ compensation insurance endorsements for our general partner under our secondment agreement. On December 20, 2012, in connection with the CMO Acquisition, we entered into another 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. The secondment agreement, employee transfer agreement and shared services agreement each terminated on January 1, 2013 in accordance with the letter agreements.
Gas Gathering Agreements
On December 20, 2012, in connection with the closing of the CMO Acquisition, we entered into new gas gathering agreements with certain subsidiaries of Chesapeake. Each gas gathering agreement defines the services, fees and obligations of the parties with respect to a particular oil and natural gas geologic formation or producing region of the United States. The terms of the applicable agreement for each region are summarized below.
Eagle Ford Shale Region
We entered into a 20-year natural gas gathering agreement with certain subsidiaries of Chesapeake and other producers pursuant to which we provide gathering, compression, dehydration and treating services for natural gas delivered by Chesapeake and other producers to our gathering systems in our Eagle Ford Shale region. We gather, compress, dehydrate and treat natural gas in exchange for a cost of service based fee for natural gas gathered and treated on our gathering systems. The cost of service components include revenue, compression expense, deemed
general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics (collectively, the “Eagle Ford Fee”). Subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas owned or controlled by it and produced from the Eagle Ford Shale formation through existing and future wells with a surface location within the dedicated area in the Eagle Ford Shale region.
During 2013 and 2014, the Eagle Ford Fee is determined by a fee tiering mechanism that calculates the Eagle Ford Fee on a monthly basis according to the quantity of gas delivered to us by Chesapeake relative to its scheduled deliveries. Effective on January 1, 2015 and January 1st of each year thereafter for a period of 20 years from July 1, 2012, the Eagle Ford Fee will be redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital. There is no cap on these adjustments.
Subject to required notice by Chesapeake, we have the option to connect new operated wells within our Eagle Ford Shale region acreage dedications as requested by Chesapeake. If we elect not to connect a new operated well, Chesapeake will be provided alternative forms of release. Subject to certain conditions specified in the gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections, up to a specified cap, and the potential for a well pad release from the producer’s acreage dedication at the producer’s option.
We have also agreed with Chesapeake to a cap on fuel and lost and unaccounted for gas on our systems with respect to Chesapeake’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period and do not respond in a timely manner with a proposed solution, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then-current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.
Haynesville Shale Region - Mansfield Gathering System
We entered into a 20-year natural gas gathering agreement with certain subsidiaries of Chesapeake and other producers pursuant to which we provide gathering, dehydration, compression and treating services for natural gas delivered by Chesapeake and other producers to our gathering systems in our Haynesville Shale region. We gather, dehydrate, compress and treat natural gas in exchange for a fixed fee per MMBtu for natural gas gathered on our gathering systems (the “Mansfield Fee”). The Mansfield Fee is subject to an annual 2.5% rate escalation at the beginning of each year.
Subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas owned or controlled by it and produced from the Bossier and Haynesville formation through existing and future wells located with a surface location within the Haynesville Shale region acreage dedication. Chesapeake has also agreed to minimum volume commitments for each year through December 31, 2017. If Chesapeake does not meet its minimum volume commitments to us, as adjusted in certain instances, for any annual period during the minimum volume commitment period, Chesapeake will be obligated to pay us the difference between the minimum volume commitment and the volume of gas delivered from Chesapeake’s wells. During the minimum volume commitment period, the Mansfield Fee is a fixed fee on all monthly volumes. Subsequent to that period, Chesapeake will pay a tiered fee that calculates the Mansfield Fee on a monthly basis according to the quantity of gas delivered to us from Chesapeake wells relative to its scheduled deliveries.
We have certain connection obligations for new operated wells of Chesapeake in the acreage dedications. Chesapeake is required to provide us notice of new wells that it operates in the acreage dedications. Subject to certain conditions specified in the gas gathering agreement, we are generally required to connect new wells within specified timelines subject to minimum volume commitment delays for volume that would have been received from the new wells during the minimum volume commitment period and penalties up to a specified cap after the minimum volume commitment period.
We have agreed with Chesapeake on percentage-based caps on fuel and lost and unaccounted for gas on our systems with respect to Chesapeake’s volumes. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.
Marcellus Shale Region
We entered into a 15-year natural gas gathering agreement with certain subsidiaries of Chesapeake and other producers pursuant to which we provide gathering, compression and dehydration services for natural gas delivered
by Chesapeake and other producers to our gathering systems in our Marcellus Shale region. We gather, compress and dehydrate natural gas in exchange for a cost of service based fee for natural gas gathered on our gathering systems. The cost of service components include compression expense, deemed general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics (collectively, the “Marcellus Fee”). Effective on January 1, 2014 and January 1st of each year thereafter for a period of 15 years from July 1, 2012, the Marcellus Fee will be redetermined based on a cost of service calculation that provides a specified pre-income tax rate of return on invested capital.
Subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on natural gas and oil leases covering lands within an acreage dedication in the Marcellus region. Chesapeake’s dedication of the natural gas produced from applicable dedicated properties will run with the land in order to bind successors to Chesapeake’s interest, as well as any natural gas interests in the dedicated properties subsequently acquired by Chesapeake.
Subject to required notice by Chesapeake, we will have the option to connect new operated wells within our Marcellus region acreage dedications as requested by Chesapeake. If we elect not to connect a new operated well, Chesapeake will be provided alternative forms of release. Subject to certain conditions specified in the gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections up to a specified cap. If the well is delayed for more than one year, then the well pad may be released from Chesapeake’s acreage dedication at Chesapeake’s option.
We have agreed with Chesapeake to a cap on fuel and lost and unaccounted for gas on our systems with respect to Chesapeake’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period and do not respond in a timely manner with a proposed solution, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.
Niobrara Shale Region
We entered into a 20-year natural gas gathering agreement with certain subsidiaries of Chesapeake and other producers pursuant to which we provide gathering, compression, dehydration and processing services for natural gas delivered by Chesapeake and other producers to our gathering systems in our Niobrara Shale region. We gather, compress, dehydrate and process natural gas in exchange for a cost of service based fee for natural gas gathered on our gathering systems and for natural gas processed at our processing facility. The cost of service components will include revenue, compression expense, deemed general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics (collectively, the “Niobrara Fee”). Effective on January 1, 2014 and January 1st of each year thereafter for a period of 20 years from July 1, 2012, the Niobrara Fee will be redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital. There is no cap on these fee adjustments.
Subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas and liquids owned or controlled by it and produced from the Frontier Sand and the Niobrara Shale through existing and future wells with a surface location within the designated dedicated areas. Chesapeake’s dedication of the natural gas produced from applicable dedicated properties will run with the land in order to bind successors to Chesapeake’s interest, as well as any natural gas interests in the dedicated properties subsequently acquired by Chesapeake.
Subject to required notice by Chesapeake, we will have the option to connect new operated wells within our Niobrara region acreage dedications as requested by Chesapeake. If we elect not to connect a new operated well, Chesapeake will be provided alternative forms of release. Subject to certain conditions specified in the gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections up to a specified cap, and the potential for a well pad release from the producer’s acreage dedication at the producer’s option.
We have agreed with Chesapeake to a cap on fuel and lost and unaccounted for gas on our systems with respect to Chesapeake’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period and do not respond in a timely manner with a proposed solution, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.
Utica Shale Region
We entered into a 15-year natural gas gathering agreement with certain subsidiaries of Chesapeake and other producers pursuant to which we provide gathering, compression and dehydration services for natural gas and liquids delivered by Chesapeake and other producers to our gathering systems in our Utica Shale region. We gather, compress and dehydrate natural gas and liquids in exchange for a cost of service based fee for natural gas gathered on our gathering systems. The cost of service components will include revenue, compression expense, deemed general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics (collectively, the “Utica Fee”). Beginning on January 1, 2014 and annually thereafter, for a period of 20.75 years from 15 years from July 1, 2012, the gathering fee portion of the Utica Fee will be redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital.
Subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas and liquids owned or controlled by it and produced from the Utica Shale formation existing and future wells with a surface location within the designated dedicated areas. Chesapeake’s dedication of the natural gas produced from applicable dedicated properties will run with the land in order to bind successors to Chesapeake’s interest, as well as any natural gas interests in the dedicated properties subsequently acquired by Chesapeake.
Subject to required notice by Chesapeake, we will have the option to connect new operated wells within our dedicated acreage as requested by Chesapeake. If we elect not to connect a new operated well, Chesapeake will be provided alternative forms of release. Subject to certain conditions specified in the gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections, up to a specified cap, and the potential for a well pad release from the producer’s acreage dedication at the producer’s option.
We have agreed with Chesapeake to a cap on fuel and lost and unaccounted for gas on our systems with respect to Chesapeake’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk. Exceeding the permitted cap does not result in a reimbursement to Chesapeake if we respond in a timely manner with a proposed solution.
Compression Agreements
We have entered into a compression agreement 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 outside the Marcellus Shale and provide certain related services. In return for providing such equipment, we have agreed to pay specified monthly rates per specified compression units, subject to an annual escalator to be applied on October 1st of each year and a redetermination of such specified monthly rates to market rates effective no later than October 1, 2016. Under the compression agreement, we have granted MidCon Compression the exclusive right to provide compression equipment to us in the acreage dedications through September 30, 2016. Thereafter, we 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 us 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.
We receive substantially all of the compression capacity for our existing gathering systems in the Marcellus Shale from MidCon Compression under a long-term contract expiring on January 31, 2021 pursuant to which we have agreed to pay specified monthly rates under a fixed-fee structure subject to an annual escalator. This agreement is not subject to an exclusivity provision.
We are obligated to maintain general liability and property insurance, including machinery breakdown insurance with respect to the leased equipment. In addition, MidCon Compression has agreed to provide us with emission testing and other related services at monthly rates. We and MidCon Compression may terminate these services upon not less than six months’ notice.
The compression agreement with respect to our gathering systems outside the Marcellus Shale expires on September 30, 2019, and our compression agreement with respect to our gathering systems in the Marcellus Shale expires on January 31, 2021, but each agreement will continue from year to year after their respective expiration dates, unless terminated by us no less than 60 days prior to the end of the term or any year thereafter. Additionally, either party may terminate in specified circumstances, including upon the other party’s failure to perform material obligations under the compression agreement if such failure is not cured within 60 days after notice thereof.
On June 15, 2012, the previously existing above-described compression agreements were amended and restated on terms substantially similar to those under the Partnership’s original compression agreements.
As part of the CMO Acquisition we acquired two compression agreements between CMO and MidCon Compression. In the first agreement, MidCon Compression provides certain compression equipment that we use to compress gas gathered on certain gathering systems in Arkansas, Colorado, Kansas, Louisiana, New Mexico, Oklahoma, Texas and Wyoming and provide certain related services. In return for providing 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 January 1, 2017. Under this compression agreement, we have granted MidCon Compression the exclusive right to provide compression equipment to us in the applicable acreage dedications through January 1, 2017. Thereafter, we will have the right to continue receiving such equipment through January 1, 2020 at market rates to be agreed upon between the parties or to receive compression equipment from unaffiliated third parties. MidCon Compression guarantees to us 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 second compression agreement is intended to cover all areas not covered by the initial CMO compression agreement. We have agreed to pay specified monthly rates under a fixed-fee structure subject to an annual escalator. This agreement is not subject to an exclusivity provision.
These compression agreements expire on the last day of the last month in which all of the compression equipment is removed from our facilities. Additionally, either party may terminate the agreements in specified circumstances, including upon the other party’s failure to perform material obligations under the compression agreements if such failure is not cured within 60 days after notice thereof.
In all of the above compression contracts, we are 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 us with emission testing and other related services at monthly rates. We and MidCon Compression may terminate these services upon not less than six months’ notice.
Master Recoupment, Netting and Setoff Agreement
We have entered into a master recoupment, netting and setoff agreement with Chesapeake and certain of its subsidiaries. The recoupment agreement provides for the netting of fees, liquidated damages and other charges between the parties to certain “covered agreements,” including the gas gathering agreement with Chesapeake, the termination agreement and the transition 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.
Registration Rights Agreement
We have entered into 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.
CMO Acquisition
On December 11, 2012, the Partnership and CMD entered into a Unit Purchase Agreement (the “Unit Purchase Agreement”). Pursuant to the terms of the Unit Purchase Agreement, the Partnership agreed to purchase, and CMD agreed to sell, 100% of the issued and outstanding equity interests in CMO, which together with its subsidiaries owns certain midstream gas gathering, processing and related assets in the Eagle Ford, Utica, Niobrara, Haynesville, Marcellus and Mid-Continent regions.
The acquisition closed on December 20, 2012. The aggregate consideration the Partnership paid to CMD was approximately $2.16 billion, subject to post-closing adjustments. The purchase price was funded with proceeds from the issuance of senior notes, the issuance of common units and the sale of Class B units and Class C units.
Pursuant to the Unit Purchase Agreement and subject to certain limitations and survival periods, CMD and the Partnership have agreed to indemnify each other and their respective affiliates, officers, directors and other representatives against certain losses resulting from any breach of their representations, warranties or covenants contained in the Unit Purchase Agreement. CMD also has agreed to indemnify the Partnership for certain specified contingencies and liabilities, as well as liabilities related to certain excluded assets and entities. CMD’s indemnity obligations with respect to environmental matters and matters related to the acquired assets and related easements will terminate after seven years and its indemnity obligations with respect to matters relating to reserves and production and dedicated acreage will terminate after five years.
In connection with the CMO Acquisition, the Partnership entered into five new gathering and processing agreements, an operating agreement, a transition services agreement, an amendment to the Partnership’s June 2012 transition side letter, a master recoupment and set-off agreement and a non-solicitation agreement, each as described above. In addition, at the closing of the CMO Acquisition, certain provisions of the omnibus agreement entered into between the Partnership and affiliates of Chesapeake at the time of the Partnership’s initial public offering were terminated. See “-Gas Gathering Agreements,” “-Operating Agreement,” “-Transition Services Agreement,” “-Compression Agreements,” “-Termination Agreement” and “-Non-Solicitation Agreement.”
All of the parties to the acquisition and related agreements described herein are subsidiaries or affiliates of Chesapeake. The terms of the CMO Acquisition and related agreements were approved by the Partnership’s general partner’s board of directors and by the board’s conflicts committee. The conflicts committee, a committee comprised of the independent members of the Partnership’s general partner’s board of directors, retained independent legal and financial advisors to assist it in evaluating and negotiating the acquisition. In approving the acquisition, the conflicts committee based its decision in part on an opinion from the independent financial advisor that the consideration to be paid by the Partnership was fair, from a financial point of view, to the Partnership.
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, for cash consideration of approximately $1.82 billion. 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 our general partner.
Review, Approval or Ratification of Transactions with Related Persons
Our Code of Ethics sets forth our policies for the review, approval and ratification of transactions with related persons. Under the Code of Ethics, a director is expected to bring to the attention of the chief executive officer or the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict will be addressed in accordance with 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
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:
•
approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval;
•
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
•
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
•
fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
Our general partner may, but is not required under our partnership agreement to, seek the approval of such resolution from the conflicts committee of its board of directors. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to reasonably believe he is acting in the best interests of the partnership.
Director Independence
The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner. For a discussion of the independence of the board of directors of our general partner, please see “Item 10. Directors, Executive Officers and Corporate Governance-Management of the Partnership.”
ITEM 14.
ITEM 14. Principal Accountant Fees and Services
We have engaged PricewaterhouseCoopers LLP as our independent registered public accounting firm. The following table summarizes the fees we have paid PricewaterhouseCoopers LLP to audit the Partnership’s annual consolidated financial statements and for other services for each of the last two fiscal years:
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 include the audit and review, respectively, of the Marcellus gas gathering system 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.
Audit Committee Approval of Audit and Non-Audit Services
The Audit Committee of the Partnership’s general partner has adopted a Pre-Approval Policy with respect to services which may be performed by PricewaterhouseCoopers LLP. This policy lists specific audit-related services as well as any other services that PricewaterhouseCoopers LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional Audit Committee authorization. The Audit Committee receives quarterly reports on the status of expenditures pursuant to that Pre-Approval Policy. The Audit Committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the Audit Committee or by its Chairman, to whom such authority has been conditionally delegated, prior to engagement. During 2011, no fees for services outside the scope of audit, review, or attestation that exceed the waiver provisions of 17 CFR 210.2-01(c)(7)(i)(C) were approved by the Audit Committee.
The Audit Committee has approved the appointment of PricewaterhouseCoopers LLP as independent registered public accounting firm to conduct the audit of the Partnership’s consolidated financial statements for the year ended December 31, 2011.
PART IV
ITEM 15.
ITEM 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as part of this report:
1. Financial Statements. Reference is made to the accompanying Index to Financial Statements.
2. Financial Statement Schedules. Schedule II is included in Item 8 of this report with our consolidated financial statements. No other financial statement schedules are applicable or required.
3. Exhibits. The following exhibits are filed herewith pursuant to the requirements of Item 601 of Regulation S-K:
 Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
* Management contract or compensatory plan or arrangement.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ACCESS MIDSTREAM PARTNERS, L.P.
By: Access Midstream Partners GP, L.L.C., its general partner
Date: February 25, 2013
By
/S/ J. MIKE STICE
J. Mike Stice
Chief Executive Officer
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints J. Mike Stice and David C. Shiels, and each of them, either one of whom may act without joinder of the other, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all amendments to this Annual Report on Form 10-K, and to file the same, with all, exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each, and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, and each of them, or the substitute or substitutes of any or all of them, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
INDEX TO EXHIBITS
 Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
* Management contract or compensatory plan or arrangement.