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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the Fiscal Year Ended December 31, 2010
or
[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to
Commission File No. 1-34831
Chesapeake Midstream Partners, L.P.
(Exact name of registrant as specified in its charter)
| Delaware | 80-0534394 | |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
| 900 NW 63rd Street | ||
| Oklahoma City, Oklahoma | 73118 | |
| (Address of principal executive offices) | (Zip Code) | |
(405) 935-1500
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class |
Name of Each Exchange on Which Registered | |||
| Common Units Representing Limited Partner Interests |
New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES [ ] NO [X]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
YES [ ] NO [X]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES [ ] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer [ ] Accelerated Filer [ ] Non-accelerated Filer [X] Smaller Reporting Company [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES [ ] NO [X]
The registrant was not a public company as of the last business day of its most recently completed second fiscal quarter and, therefore, cannot calculate the aggregate market value of its common units held by non-affiliates as of such date.
As of March 7, 2011, there were 69,084,576 common units outstanding.
Table of Contents
CHESAPEAKE MIDSTREAM PARTNERS, L.P.
2010 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
| PART I | Page | |||||
| Item 1. |
1 | |||||
| Item 1A. |
11 | |||||
| Item 1B. |
33 | |||||
| Item 2. |
33 | |||||
| Item 3. |
34 | |||||
| Item 4. |
34 | |||||
| PART II | ||||||
| Item 5. |
34 | |||||
| Item 6. |
36 | |||||
| Item 7. |
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
37 | ||||
| Item 7A. |
55 | |||||
| Item 8. |
56 | |||||
| Item 9. |
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
80 | ||||
| Item 9A. |
80 | |||||
| Item 9B. |
80 | |||||
| PART III | ||||||
| Item 10. |
80 | |||||
| Item 11. |
86 | |||||
| Item 12. |
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters |
103 | ||||
| Item 13. |
Certain Relationships and Related Transactions and Director Independence |
105 | ||||
| Item 14. |
120 | |||||
| PART IV | ||||||
| Item 15. |
121 | |||||
Table of Contents
| 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 results of Chesapeake Midstream Partners, L.L.C. from its inception on September 30, 2009 through the closing date of our initial public offering (“IPO”) on August 3, 2010 and to Chesapeake Midstream Partners, L.P. (NYSE: CHKM) and its subsidiaries thereafter. “Predecessor” refers to Chesapeake Midstream Development, L.P., which held substantially all of our assets as well as other midstream assets prior to September 30, 2009. “Chesapeake” refers to Chesapeake Energy Corporation (NYSE: CHK) and “GIP” refers to Global Infrastructure Partners – A, L.P., and affiliated funds managed by Global Infrastructure Management, L.L.C., and certain of their respective subsidiaries and affiliates. “Chesapeake Midstream Ventures” refers to Chesapeake Midstream Ventures, L.L.C., the sole member of our general partner. “Total”, when discussing the upstream joint venture with Chesapeake, refers to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (NYSE: TOT, FP: FP), and when discussing our gas gathering agreement and related matters, refers to Total E&P USA, Inc. and Total Gas & Power North America, Inc., a wholly owned subsidiary of Total S.A.
General
We are a growth-oriented publicly-traded Delaware limited partnership formed by Chesapeake and GIP to own, operate, develop and acquire natural gas gathering systems and other midstream energy assets. We are principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. The following diagram illustrates our area of focus in the natural gas value chain:
We provide gathering, treating and compression services to Chesapeake and Total, our primary customers, and other third-party producers under long-term, fixed-fee contracts. Our gathering systems operate in our Barnett Shale region in north-central Texas, our Haynesville Shale region in northwest Louisiana and our Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian Basins. We generate the majority of our operating income in our Barnett Shale region, where we service approximately 1,840 wells in the core of the prolific Barnett Shale. Our Springridge gathering system services approximately 164 wells in one of the core areas of the Haynesville Shale. In our Mid-Continent region, we have an enhanced focus on the unconventional resources located in the Colony Granite Wash and Texas Panhandle Granite Wash plays of the Anadarko Basin. In total, our systems consist of approximately 3,370 miles of gathering pipelines, servicing approximately 4,360 natural gas wells. For the year ended December 31, 2010, our assets gathered approximately 1.6 billion cubic feet (“Bcf”) of natural gas per day. Following the acquisition of the Springridge gathering system in December 2010, our assets gathered approximately 2.0 Bcf per day.
Our gas gathering systems primarily collect natural gas from unconventional resource plays, a growing source of U.S. natural gas supply that is generally characterized by low finding and development costs compared to conventional resource plays. These systems were historically operated by Chesapeake and are integral to Chesapeake’s operations in our Barnett Shale, Haynesville Shale and Mid-Continent regions.
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We generate substantially all of our revenues through long-term, fixed-fee natural gas gathering, treating and compression contracts that limit our direct commodity price exposure. We have entered into 20-year natural gas gathering agreements with Chesapeake and Total, Chesapeake’s upstream joint venture partner, in our Barnett Shale region, and with Chesapeake in our Mid-Continent region. We have also entered into a 10-year natural gas gathering agreement with Chesapeake in our Haynesville Shale region. Pursuant to these gas gathering agreements, Chesapeake and Total have agreed to provide us with extensive acreage dedications in our Barnett Shale region and, with respect to our agreements with Chesapeake, our Haynesville Shale and Mid-Continent regions. These agreements generally require us to connect Chesapeake and Total operated natural gas drilling pads and wells within our acreage dedications to our gathering systems and contain the following terms:
| • | minimum volume commitments for 10 years in our Barnett Shale region and for three years in our Haynesville Shale regions, which mitigate throughput volume variability; |
| • | fee redetermination mechanisms in our Barnett Shale, Haynesville Shale and Mid-Continent regions, which are designed to support a return on invested capital and allow our gathering rates to be adjusted, subject to specified caps, to account for variability in revenues, capital expenditures and compression expenses; and |
| • | price escalators in our Barnett Shale, Haynesville Shale and Mid-Continent regions, which annually increase our gathering rates. |
Initial Public Offering
On August 3, 2010, we completed our IPO of 24,437,500 common units (amount includes 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option on August 3, 2010) at a price of $21.00 per unit. Our common units are listed on the New York Stock Exchange (the “NYSE”) under the symbol “CHKM”.
We received gross offering proceeds of approximately $513.2 million less approximately $38.6 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of the contribution agreement, we distributed the approximate $62.4 million of net proceeds from the exercise of the over-allotment option to GIP on August 3, 2010. We used the net offering proceeds of $412.2 million to repay approximately $110.0 million of borrowings under our revolving credit facility and to pay approximately $5.1 million of fees related to the amendment of our revolving credit facility. The remainder was used to fund expansion capital expenditures and part of the Springridge acquisition.
Upon completion of the IPO, we had outstanding 69,076,122 common units, 69,076,122 subordinated units, a two percent general partner interest and incentive distribution rights (“IDRs”). IDRs entitle the holder to specified increasing percentages of cash distributions as the Partnership’s per-unit cash distributions increase above specified levels. At the close of the IPO, common units held by the public represented 17.7 percent of all outstanding limited partner interests, and Chesapeake and GIP held 42.3 percent and 40.0 percent, respectively, of all outstanding limited partner interests. The limited partners, collectively, hold a 98.0 percent limited partner interest in the Partnership and the general partner, which is owned and controlled by Chesapeake and GIP, holds a two percent general partner interest in the Partnership.
Upon completion of the IPO, Chesapeake and GIP conveyed to us a 100 percent membership interest in Chesapeake MLP Operating, L.L.C., which owned all of our assets since September 2009.
Springridge Gathering System Acquisition
On December 21, 2010, we acquired the Springridge gathering system and related facilities from Chesapeake Midstream Development, L.P., a wholly owned subsidiary of Chesapeake, for $500.0 million. The Springridge gathering system consists of 226 miles of gathering pipeline primarily located in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, we entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication, annual fee redetermination and a three-year minimum volume commitment.
The acquisition was financed with a draw on the Partnership’s revolving credit facility of approximately $234.0 million plus approximately $266.0 million of cash on hand. The results of operations presented and discussed in this annual report include results of operations from the Springridge gathering system for the 11-day period from closing of the acquisition on December 21, 2010, through December 31, 2010.
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Our Assets and Areas of Operation
Prior to closing of the Springridge acquisition, we generated approximately 78 percent of our revenues from our gathering systems in our Barnett Shale region and approximately 22 percent of our revenues from our gathering systems in our Mid-Continent region. The following table summarizes average daily throughput and assets by region as of and for the year ended December 31, 2010:
| Region |
Location (State(s)) |
Average Throughput (Bcf/d) |
Approximate Length (Miles) |
Approximate Number of Wells Serviced |
Gas Compression (Horsepower)(2) |
|||||||||||||
| Barnett Shale |
TX | 1.025 | 781 | 1,835 | 138,435 | |||||||||||||
| Haynesville Shale(1) |
LA | 0.444 | 226 | 164 | 11,320 | |||||||||||||
| Mid-Continent |
TX, OK, KS, AR | 0.557 | 2,358 | 2,356 | 86,251 | |||||||||||||
| Total |
3,365 | 4,355 | 236,006 | |||||||||||||||
| (1) | Throughput, after completion of the Springridge acquisition, from December 21, 2010, through December 31, 2010, was 0.444 Bcf/d. |
| (2) | Substantially all of our gas compression is provided by compression equipment leased from a subsidiary of Chesapeake. |
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Barnett Shale Region
General. Our gathering systems in our Barnett Shale region are primarily located in Tarrant, Johnson and Dallas counties in Texas in the Core and Tier 1 areas of the Barnett Shale and currently consist of 25 interconnected gathering systems and 781 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, 2010, was 1.025 Bcf per day. We connect our gathering systems to receipt points that are either at the individual wellhead or at central receipt points into which production from multiple wells are gathered. Due to Chesapeake’s practice of drilling multiple wells on an individual drilling pad, a significant number of our receipt points in the Barnett Shale collect production from multiple producing wells. Our Barnett Shale system has pipeline diameters ranging from four-inch well connection lines to 24-inch major trunk lines and is connected to 95 compressor units providing a combined 138,435 horsepower of compression.
Delivery Points. Our Barnett Shale gathering system is connected to the following downstream transportation pipelines:
| • | Atmos Pipeline Texas – natural gas delivered into this pipeline system serves the greater Dallas/Fort Worth metropolitan area and south, east and west Texas markets at the Katy, Carthage and Waha hubs; |
| • | Energy Transfer Pipeline Texas – natural gas delivered into this pipeline system serves the greater Dallas/Fort Worth metropolitan area and southeastern and northeastern U.S. markets supplied by the Midcontinent Express Pipeline, Centerpoint CP Expansion Pipeline and Gulf South 42” Expansion Pipeline; and |
| • | Enterprise Texas Pipeline – natural gas delivered into this pipeline system serves the greater Dallas/Fort Worth metropolitan area and southeastern and northeastern U.S. markets supplied by the Gulf Crossing Pipeline. |
Haynesville Shale Region
General. Our Springridge gas gathering system in the Haynesville Shale region is primarily located in Caddo and DeSoto Parishes, Louisiana, in one of the core areas of the Haynesville Shale and currently consists of 226 miles of pipeline. The core areas are characterized by thicker natural gas bearing geological zones, which results in higher initial production rates. Haynesville Shale gas production is characterized as “lean” and typically needs to be treated to remove small amounts of carbon dioxide and hydrogen sulfide.
A portion of our assets in the Springridge gathering system have been designed and developed to accommodate their urban setting in and around the city of Shreveport, Louisiana. Average throughput on our Springridge gathering system from the date of acquisition through the month ended December 31, 2010, was 0.444 Bcf per day. We connect our gathering systems to receipt points that are either at the individual wellhead or at central receipt points into which production from multiple wells is gathered. Chesapeake’s pad drilling concept is used extensively around the Springridge gathering system. Our Springridge gathering system has pipeline diameters ranging from four-inch well connection lines to a 24-inch major trunk line and is connected to seven compressor units providing a combined 11,320 horsepower of compression.
Delivery Points. Our Springridge gathering system is connected to the following downstream transportation pipelines:
| • | Centerpoint Energy Gas Transmission – natural gas delivered into this 42” diameter pipeline can be received at the Carthage, Texas, and Perryville, Louisiana, Hubs, and is connected to numerous interstate pipelines; |
| • | ETC Tiger Pipeline – natural gas delivered into this 42” diameter pipeline can also be received at the Carthage and Perryville Hubs. ETC Tiger Pipeline provides deliveries to seven interstate pipelines and one intrastate pipeline for ultimate delivery to the Midwest and Northeast regions of the U.S.; and |
| • | Texas Gas Transmission Pipeline – natural gas delivered into this pipeline can move to on-system markets in the Midwest region and to off-system markets in the Northeast region via interconnections with third-party pipelines or it can be received at the Carthage Hub in the East Texas region. |
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Mid-Continent Region
Our Mid-Continent gathering systems extend across portions of Oklahoma, Texas (excluding the Barnett Shale), Arkansas (excluding the Fayetteville Shale) and Kansas. Included in our Mid-Continent region are three treating facilities located in Beckham and Grady Counties, Oklahoma, and Reeves County, Texas, that are designed to remove contaminants from the natural gas stream.
Anadarko Basin and Northwest Oklahoma
General. Our assets within the Anadarko Basin and Northwest Oklahoma region are located in northwestern Oklahoma and the northeastern portion of the Texas Panhandle and consist of approximately 1,448 miles of pipeline. Our Anadarko Basin and Northwest Oklahoma region gathering systems had an average throughput for the year ended December 31, 2010 of 0.335 Bcf per day. These systems are connected to 57 compressor units providing a combined 46,671 horsepower of compression.
Within the Anadarko Basin, we are primarily focused on servicing Chesapeake’s production from the Colony Granite Wash and Texas Panhandle Granite Wash plays. Natural gas production from these areas of the Anadarko Basin typically contains a significant amount of natural gas liquids (“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 region 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 329 miles of pipeline across the Permian and Delaware basins. Average throughput on our gathering systems for the year ended December 31, 2010, was 0.085 Bcf per day. The systems have pipeline diameters ranging from four inches to 16 inches and are connected to 19 compressor units providing a combined 13,845 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 Region
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 region and the Gulf Coast region of Texas. The other Mid-Continent assets include approximately 581 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, 2010 was 0.137 Bcf per day. The systems have pipeline diameters ranging from four inches to 24 inches and are connected to 41 compressor units providing a combined 25,735 horsepower of compression.
General Trends
In 2010, we observed a shift in drilling activity by Chesapeake and other producers from the dry gas shale plays such as the Barnett Shale to the liquids rich plays like our Mid-Continent region. We believe this trend is likely to continue for the foreseeable future. Any decrease in production in the Barnett Shale will be offset as our contractual protections of minimum volume commitment and rate redetermination work to maintain our financial performance in that region.
We believe this trend may present an opportunity for us to enter the market of gathering and transporting oil as we believe those services fit well with our current business model.
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The recent natural gas price environment has resulted in lower drilling activity generally, resulting in fewer new well connections and, in some cases, temporary curtailments of production throughout the areas in which we operate. A continued low gas price environment may result in further reductions in drilling activity or temporary curtailments of production. We have no control over this activity. In addition, further decline in commodity prices could affect production rates and the level of capital invested by Chesapeake and third parties in the exploration for and development of new natural gas reserves. Our success in connecting new wells to our systems is dependent on natural gas producers and shippers.
On January 6, 2011, Chesapeake announced its “25/25 Plan”, which calls for a 25% reduction in its outstanding long-term debt while growing net natural gas and oil production by 25% by the end of 2012. They expect to achieve the reduction in debt through asset monetizations including the proposed sale of Chesapeake’s Fayetteville assets announced in February 2011. The proposed sale would prevent us from acquiring the Fayetteville midstream assets from Chesapeake; however the proposed sale will allow Chesapeake to reduce its debt level. Among the several benefits of Chesapeake’s lower debt is the possibility that it will lead to a more favorable debt rating by the major ratings agencies if and when we request a rating.
Competition
Given that substantially all of the natural gas gathered and transported through our systems is owned by Chesapeake, Total and their working interest partners within our acreage dedications, we do not currently face significant competition for our natural gas volumes. In addition, Chesapeake and Total have dedicated all of their natural gas produced from existing and future wells located on lands within our acreage dedication in the Barnett Shale region, and Chesapeake has made a similar dedication in our Haynesville and Mid-Continent regions.
In the future, we may face competition for Chesapeake’s production drilled outside of our acreage dedication and in attracting third-party volumes to our systems. Additionally, to the extent we make acquisitions from third parties we could face incremental competition. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies. We currently anticipate that our competitors in each region would include:
| • | Barnett Shale – Energy Transfer Partners, Crosstex Energy, Crestwood Midstream Partners, Freedom Pipeline, Peregrine Pipeline, XTO Energy, EOG Resources, DFW Mid-Stream and Enbridge Energy Partners; |
| • | Haynesville Shale – TGGT Holdings, L.L.C., Enterprise Products Partners, L.P., Kinderhawk Field Services, CenterPoint Field Services, and Energy Transfer Partners; and |
| • | Mid-Continent – Enogex, Atlas Pipeline Partners, Enbridge and DCP Midstream. |
Employees
At every level of our operations, our employees are critical to our success and committed to operational excellence. Our senior management team has impressive experience building, acquiring and managing midstream and other assets. Their focus is on optimizing our business and expanding operations. On an operations level, our supervisory and field personnel are empowered with the training, tools and confidence required to succeed in their jobs.
The officers of our general partner manage our operations and activities. As of December 31, 2010, our general partner and Chesapeake jointly employed approximately 285 people who operate our business pursuant to an employee secondment agreement between our general partner and Chesapeake and certain of Chesapeake’s affiliates and, with respect to our Chief Executive Officer, pursuant to a shared services agreement between our general partner and Chesapeake. None of these employees are covered by collective bargaining agreements and our general partner and Chesapeake consider their employee relations to be good.
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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. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas. The PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways.
We or the entities in which we own an interest inspect our pipelines regularly using equipment rented from third-party suppliers. Third parties also assist us in interpreting the results of the inspections.
States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.
In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency (“EPA”) community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.
Regulation of Operations
Natural gas gathering and intrastate transportation facilities are exempt from the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act. 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.
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.
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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.
Environmental Matters
General
Our operation of pipelines, plants and other facilities for the gathering, treating and compressing of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations can restrict or impact our business activities in many ways, such as:
| • | requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of our wastes; |
| • | limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species; |
| • | requiring investigatory and remedial actions to limit pollution conditions caused by our operations or attributable to former operations; and |
| • | prohibiting the operations of facilities deemed to be in non-compliance with permits issued pursuant to such environmental laws and regulations. |
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial obligations, and the issuance of orders enjoining future operations or imposing additional compliance requirements. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.
Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.
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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, including hazardous wastes, that are subject to the requirements of the Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements relating to the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.
We currently own or lease, and our Predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.
Air Emissions
Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. For example, the Texas Commission on Environmental Quality has recently adopted new rules governing emissions of regulated pollutants from oil and natural gas facilities and continues to evaluate existing air regulations and proposed revisions to existing regulations as well as seek to promulgate new regulations that meet or exceed federal requirements. Such revised or new rules would establish new limits on emissions from some of our facilities as well as require implementation of best practices and/or technology and new monitoring and record keeping requirements. In addition, 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.
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Water Discharges
The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the U.S. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition, results of operations or cash flow.
Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used by our customers to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and a small percentage of chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is regulated by state agencies, typically the state’s oil and gas commission. 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.
Endangered Species
The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in 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.
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. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including certain natural gas processing facilities, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. 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.
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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 between us, as lessee, and the fee owner of the lands, as lessors. We, or our Predecessor, have leased or owned 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.
Risks Related to Our Business
We are dependent on Chesapeake for a substantial majority of our revenues. Therefore, we are indirectly subject to the business risks of Chesapeake. We have no control over Chesapeake’s business decisions and operations, and Chesapeake is under no obligation to adopt a business strategy that favors us.
Historically, we have provided substantially all of our natural gas gathering, treating and compressing services to Chesapeake and its working interest partners. For the year ended December 31, 2010, Chesapeake and its working interest partners accounted for approximately 93 percent of the natural gas volumes on our gathering systems and 97 percent of our revenues. We expect to derive a substantial majority of our revenues from Chesapeake for the foreseeable future. Therefore, any event, whether in our area of operations or otherwise, that adversely affects Chesapeake’s production, financial condition, leverage, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the business risks of Chesapeake, some of which are the following:
| • | the volatility of natural gas and oil prices, which could have a negative effect on the value of its oil and natural gas properties, its drilling programs or its ability to finance its operations; |
| • | the availability of capital on an economic basis to fund its exploration and development activities; |
| • | its ability to replace reserves, sustain production and begin production on certain leases that may otherwise expire; |
| • | uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production; |
| • | its drilling and operating risks, including potential environmental liabilities; |
| • | transportation capacity constraints and interruptions; |
| • | adverse effects of governmental and environmental regulation; and |
| • | losses from pending or future litigation. |
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If Chesapeake and Total do not increase the volumes of natural gas they provide to our gathering systems, our growth strategy and ability to increase cash distributions to our unitholders may be adversely affected.
Unless we are successful in attracting significant unaffiliated third-party customers, our ability to increase the throughput on our gathering systems will be dependent on receiving increased volumes from Chesapeake and Total. Other than the scheduled increases in the minimum volume commitments provided for in our gas gathering agreements with Chesapeake and Total, neither Chesapeake nor Total is 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’s recently-announced intent to increase operations in liquids-rich areas could result in Chesapeake decreasing drilling in predominantly dry gas areas such as our Barnett Shale and Haynesville Shale regions. A reduction in the natural gas volumes supplied by Chesapeake and Total 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 and the two percent general partner interest outstanding. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
| • | the volume of natural gas we gather, treat and compress; |
| • | the level of production of, the demand for, and, indirectly, the price of natural gas; |
| • | the level of our operating and general and administrative costs; |
| • | regulatory action affecting the supply of or demand for natural gas, our operations, the rates we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and |
| • | prevailing economic conditions. |
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
| • | the level of capital expenditures we make, including capital expenditures for connecting new operated drilling pads or new operated wells of Chesapeake and Total in our acreage dedications as required by our gas gathering agreements; |
| • | the cost of acquisitions, if any; |
| • | our debt service requirements and other liabilities; |
| • | fluctuations in our working capital needs; |
| • | our ability to borrow funds and access capital markets; |
| • | restrictions contained in our debt agreements; |
| • | the amount of cash reserves established by our general partner; and |
| • | other business risks affecting our cash levels. |
The amount of cash available for distribution will also be reduced by the amount we reimburse Chesapeake for its provision of certain general and administrative services and any additional services we may request from Chesapeake, each pursuant to our services agreement with Chesapeake; the costs and expenses of employees seconded to us pursuant to the employee secondment agreement; and certain costs and expenses incurred in connection with the services of Mr. Stice as the chief executive officer of our general partner pursuant to the shared services agreement. Other than the volumetric cap on general and administrative expenses included in the services agreement, our reimbursement obligations are uncapped. In addition, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. Under our partnership agreement, our general partner determines in good faith the amount of these expenses.
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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. Furthermore, a higher level of indebtedness at Chesapeake increases the risk that it may default on its obligations, including under its gas gathering agreements with us. Such a default could occur after the conversion of the subordinated units as a result of our general partner’s ability, for purposes of testing whether the subordination period has ended, to include as “earned” in a particular quarter its prorated estimates of shortfall payments to be earned by the end of the then current calendar year under the minimum volume commitments of our gas gathering agreements. As of December 31, 2010, Chesapeake had long-term indebtedness of approximately $12.6 billion, with $3.6 billion of outstanding borrowings drawn under its $4.0 billion revolving credit facility and $94 million of outstanding borrowings drawn under its $300 million midstream revolving credit facility. The covenants contained in the agreements governing Chesapeake’s outstanding and future indebtedness may limit its ability to borrow additional funds for development and make certain investments, which also may reduce the volumes Chesapeake delivers to our gathering systems.
Chesapeake’s debt ratings for its senior notes are currently below investment grade. If these ratings are lowered in the future, the interest rate and fees Chesapeake pays on its revolving credit facilities will increase. In addition, although we have no indebtedness rated by any credit rating agency, we may have rated debt in the future. Credit rating agencies such as Standard & Poor’s and Moody’s will likely consider Chesapeake’s debt ratings when assigning ours because of Chesapeake’s ownership interest in us, the significant commercial relationships between Chesapeake and us, and our reliance on Chesapeake for a substantial majority of our revenues. If one or more credit rating agencies were to downgrade the outstanding indebtedness of Chesapeake, we could experience an increase in our borrowing costs or difficulty accessing the capital markets. Such a development could adversely affect our ability to grow our business and to make cash distributions to our unitholders.
Our general partner may guarantee or pledge any or all of its assets (other than its general partner interest, except as permitted by the partnership agreement) to secure the indebtedness of any of its affiliates. If our general partner were required to honor its guarantee or if lenders foreclosed on our general partner’s assets, the ability of our general partner to manage our business might be adversely affected. If our general partner were unable to meet any obligations to such lenders, it might be required to file for bankruptcy, which would cause our dissolution under our partnership agreement and which might have other adverse effects.
In addition to Chesapeake, we are dependent on Total for a significant amount of the natural gas that we gather, treat and compress. A material reduction in Total’s production gathered, treated or compressed by us may result in a material decline in our revenues and cash available for distribution.
We rely on Total for a significant amount of the natural gas that we gather, treat and compress. Total may suffer a decrease in production volumes in the areas serviced by us. We are also subject to the risk that Total may default on its obligations under its gas gathering agreement with us. Neither of our Total counterparties under our gas gathering agreement, nor the Total guarantor of those counterparties’ obligations, are rated by credit rating agencies. Accordingly, this risk may be more difficult to evaluate than it would be with a rated contract counterparty. A loss of a significant portion of the natural gas volumes supplied by Total, or any nonpayment or late payment by Total 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, which is dependent on factors beyond our control. Any decrease in the volumes of natural gas that we gather could adversely affect our business and operating results.
The volumes that support our business are dependent on the level of production from natural gas wells connected to our gathering systems, the production from which may be less than we expect and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain non-dedicated sources of natural gas include (i) the level of successful drilling activity near our systems and (ii) our ability to compete for volumes from successful new wells.
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We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering systems or the rate at which production from a well declines. In addition, we have no control over Chesapeake, Total or other producers and their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected energy prices, demand for hydrocarbons, relative pricing of oil and natural gas, levels of reserves, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs, and other production and development costs.
Fluctuations in energy prices can also greatly affect the development of new natural gas reserves. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions; worldwide political conditions, such as the recent instability in Africa and the Middle East; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported liquified natural gas (“LNG”); the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional pricing differentials such as in the Mid-Continent region; the price and availability of alternative fuels; the effect of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural gas, LNG and other commodities. Declines in natural gas prices could have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our gathering and treating assets. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain levels of throughput, it could reduce our revenue and impair our ability to make cash distributions to our unitholders.
In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems in unconventional resource plays, as the basins in those plays generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Accordingly, volumes on our systems serving unconventional resource plays may need to be replaced at a faster rate to maintain or grow the current volumes than may be the case in other regions of production. In addition to significant capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to estimate higher maintenance capital expenditures over time, which will reduce our cash available for distribution from operating surplus.
If one of our gas gathering agreements were to be terminated by Chesapeake or Total as a result of our failure to perform certain obligations under the agreement, and we were unable to secure comparable alternative arrangements, our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders would be adversely affected.
Our gas gathering agreements are terminable if we fail to perform any of our material obligations and fail to correct such non-performance within specified periods; provided, however, that under certain of our gas gathering agreements if our failure to perform relates to only one or more facilities or gathering systems, such agreement is terminable only as to such facilities or systems. Additionally, if a gas gathering agreement is terminated as to only a particular Barnett Shale gathering system, the minimum volume commitment may be reduced for gas volumes that would have been gathered on the terminated gathering system. After the termination of a gas gathering agreement, we cannot assure you that Chesapeake or Total will continue to contract with us to provide gathering services, that the terms of any renegotiated agreements will be as favorable as our existing agreements or that we will be able to enter into comparable alternative arrangements with third parties. To the extent Chesapeake or Total terminates a gas gathering agreement or there is a reduction in our minimum volume commitments, our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders may be adversely affected.
Certain of the provisions contained in our gas gathering agreements may not operate as intended, including the volumetric-based cap associated with fuel, lost and unaccounted for gas and electricity, which could subject us to direct commodity price risk and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
We cannot assure you that the provisions of our gas gathering agreements will operate as intended. Our gas gathering agreements contain provisions relating to, among other items, periodic fee redeterminations, changes in laws affecting our operations and fuel, lost and unaccounted for gas and electricity.
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The fee redetermination and other provisions of our gas gathering agreements are intended to support the stability of our cash flows and were designed with the goal of supporting a return on our invested capital, which is not equivalent to ensuring that our business will generate a particular amount of cash flow. Our fee redetermination provisions do not take into consideration all expenses and other variables, including certain operating expenditures, that would affect our return on invested capital. In addition, our gathering rates may be adjusted upward or downward following a fee redetermination, subject to specified caps. The changes of law provisions contained in our gas gathering agreements are designed to provide for our reimbursement by Chesapeake and Total of certain taxes, fees, assessments and other charges that we may incur as a result of changes in law. These changes of 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 Chesapeake on MMBtu-based caps on fuel, lost and unaccounted for gas on certain of our systems with respect to Chesapeake’s volumes in our Barnett Shale and Mid-Continent regions. In the event that we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel, 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.
In the event 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 distributions to our unitholders could be adversely affected.
We do not obtain independent evaluations of natural gas reserves connected to our gathering systems; therefore, in the future, volumes of natural gas on our systems could be less than we currently anticipate.
We do not obtain independent evaluations of natural gas reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. Notwithstanding the contractual protections in our gas gathering agreements with Chesapeake and Total, including minimum volume commitments in our Barnett Shale region with respect to Chesapeake and Total, and Haynesville Shale region with respect to Chesapeake, and fee redetermination provisions, if the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
We are generally required to make capital expenditures under our gas gathering agreements with Chesapeake and Total. If we are unable to obtain needed capital or financing on satisfactory terms to fund required capital expenditures or capital expenditures to otherwise expand our asset base, our ability to grow cash distributions may be diminished or our financial leverage could increase.
Under our gas gathering agreements, upon the request of either Chesapeake or Total, we are generally required to connect new operated drilling pads and new operated wells in our Barnett Shale and Haynesville Shale regions during the respective minimum volume commitment periods, and with respect to our Mid-Continent region prior to June 30, 2019, to use commercially reasonable efforts to do the same. In addition, in order to increase our overall asset base, we will need to make significant expansion capital expenditures in the future. If we do not make sufficient or effective expansion capital expenditures, including such new drilling pad and new well connections, we will be unable to expand our business operations and will be unable to raise the level of our future cash distributions. If we are delayed in making a connection to an operated drilling pad or well, Chesapeake or Total in the Barnett Shale acreage dedication or Chesapeake in the Haynesville Shale acreage dedication, as its sole remedy for such delayed connection, would be entitled to a delay in the minimum volume obligation for gas volumes that would have been produced from the delayed connections. Any delay in the minimum volume obligations for drilling pad or well connections could reduce our revenues under the gas gathering agreements and our cash distributions.
To the extent that our cash from operations is insufficient to fund our expansion capital expenditures, we may be required to incur borrowings or raise capital through public or private debt or equity offerings. Our ability to obtain bank financing or to access the capital markets may be limited by our financial condition at the time of any such financing or offering and by the covenants in our existing debt agreements, as well as by general economic and capital market conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional common units may result in significant unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.
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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.
Our industry is highly competitive, and increased competitive pressure could adversely affect our ability to execute our growth strategy.
We compete with similar enterprises in our areas of operation other than with respect to natural gas production dedicated to us pursuant to our gas gathering agreements with Chesapeake and Total. 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 unaffiliated third parties over time. However, we have historically provided gathering and related services to third parties on only a limited basis, and we can provide no assurance that we will be able to attract any material third-party volumes to our systems. Our efforts to attract new unaffiliated customers may be adversely affected by our need to prioritize allocating capital expenditures towards connecting new operated drilling pads and new operated wells for Chesapeake and Total 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 among our potential customer base for providing high quality service in order to successfully attract material volumes from unaffiliated third parties.
If third-party pipelines or other facilities interconnected to our gathering systems become partially or fully unavailable, or if the volumes we gather do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.
Our natural gas gathering systems connect to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third-party pipelines or facilities is not within our control. These pipelines and other facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, curtailments of receipt or deliveries due to insufficient capacity or for any other reason. If any of these pipelines or facilities become unable to transport natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.
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Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand one or more of our gathering systems, the construction may occur over an extended period of time, yet we will not receive any material increases in revenues until the project is completed. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering assets may require us to obtain new rights-of-way. We may be unable to obtain such rights-of-way and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.
If we are unable to make acquisitions on economically acceptable terms from Chesapeake or third parties, our future growth would be limited, and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.
Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants, including Chesapeake. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase cash distributions to our unitholders. If we are unable to make such accretive acquisitions from Chesapeake or third parties, either because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we complete acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.
Any acquisition involves potential risks, including, among other things:
| • | mistaken assumptions about volumes, revenues and costs, including synergies; |
| • | an inability to secure adequate customer commitments to use the acquired systems or facilities; |
| • | an inability to successfully integrate the assets or businesses we acquire; |
| • | the assumption of unknown liabilities; |
| • | limitations on rights to indemnity from the seller; |
| • | mistaken assumptions about the overall costs of equity or debt; |
| • | the diversion of management’s and employees’ attention from other business concerns; |
| • | unforeseen difficulties operating in new geographic areas; and |
| • | customer or key employee losses at the acquired businesses. |
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.
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Our right of first offer with respect to certain of Chesapeake’s future midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation is subject to risks and uncertainty, and thus may not enhance our ability to grow our business.
Subject to certain exceptions, our omnibus agreement provides us with a right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation. The consummation and timing of any future transactions pursuant to the exercise of our right of first offer with respect to any particular business opportunity will depend upon, among other things, our ability to negotiate definitive agreements with respect to such opportunities and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate future transactions pursuant to these rights. Additionally, Chesapeake is under no obligation to accept any offer made by us with respect to such opportunities. Furthermore, for a variety of reasons, we may decide not to exercise these rights when they become available, and our decision will not be subject to unitholder approval. In addition, first offer rights under the omnibus agreement may be terminated by Chesapeake at any time each of GIP and Chesapeake holds less than half of the ownership interest it currently holds in Chesapeake Midstream Ventures.
Our exposure to direct commodity price risk may increase in the future.
We currently generate substantially all of our revenues pursuant to fixed-fee contracts under which we are paid based on the volumes of natural gas that we gather and treat rather than the value of the underlying natural gas. Consequently, our existing operations and cash flows have limited exposure to direct commodity price risk. Although we intend to enter into similar fixed-fee contracts with new customers in the future, our efforts to obtain such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in the future that have a greater exposure to fluctuations in commodity prices risk than our current operations. Future exposure to the volatility of oil and natural gas prices could have a material adverse effect on our business, results of operations and financial condition.
We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured, our operations and financial results could be adversely affected.
Our operations are subject to all of the risks and hazards inherent in the midstream energy business, including:
| • | damage to pipelines and facilities, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, explosions and other natural disasters and acts of terrorism; |
| • | inadvertent damage from construction, farm and utility equipment; |
| • | leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities; and |
| • | other hazards. |
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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. We are not fully insured against all risks inherent in our business. For example, we do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. Additionally, we do not have any business interruption/loss of income insurance that would provide coverage in the event of damage to any of our facilities. Although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not adequately insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets for potential environmental liabilities pursuant to our indemnification rights.
We lease substantially all of our compression capacity from a single provider under a long-term fixed price agreement, which could result in disruptions to our operations or our paying above-market prices for our compression requirements in the future.
Compression of our customers’ natural gas is a key component of the services we provide and our largest operating expense. Given that wells produce at progressively lower field pressures as the underlying resources are depleted, field compression is required to maintain sufficient pressure across our gathering systems. We lease substantially all of the compression capacity for our existing gathering systems from MidCon Compression, LLC, a wholly owned subsidiary of Chesapeake, under a long-term contract expiring on September 30, 2019 pursuant to which we have agreed to pay specified monthly rates under a fixed-fee structure subject to an annual escalator and a redetermination of such specified monthly rates to market rates effective no later than October 1, 2016. Under this agreement, we have granted MidCon Compression the exclusive right to lease and rent compression equipment to us in our Barnett Shale, Haynesville Shale and Mid-Continent acreage dedications through September 30, 2016. Thereafter, we have the right to continue leasing such equipment through September 30, 2019 at market rental rates to be agreed upon by the parties or to lease compression equipment from unaffiliated third parties. If market rates for compression are less than the specified monthly rates prior to redetermination under the agreement, then the rates we pay for compression under this contract may be higher than the rates we could obtain from a third party. In addition, if MidCon Compression were to default on its obligations under the terms of our agreement, we may not be able to replace such compression capacity in a timely manner or otherwise on terms consistent with our agreement 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 amended revolving credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our units.
We will be dependent upon the earnings and cash flow generated by our operations in order to meet our debt service obligations and to allow us to make cash distributions to our unitholders. The operating and financial restrictions and covenants in our amended revolving credit facility 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 amended revolving credit facility restricts our ability to, among other things:
| • | incur additional debt or issue guarantees; |
| • | incur or permit certain liens to exist; |
| • | make certain investments, acquisitions or other restricted payments; |
| • | modify certain material agreements; |
| • | dispose of assets; |
| • | engage in certain types of transactions with affiliates; |
| • | merge, consolidate or transfer all or substantially all of our assets; and |
| • | prepay certain indebtedness. |
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Furthermore, our amended revolving credit facility contains covenants requiring us to maintain a consolidated leverage ratio of not more than 4.50 to 1.00 and an interest coverage ratio of not less than 3.00 to 1.00.
The provisions of our amended revolving credit facility 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 amended revolving credit facility could result in an event of default which could enable our lenders, subject to the terms and conditions of the amended revolving credit facility, 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, our lenders 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 amended revolving credit facility will also have cross default provisions that apply to any other indebtedness we may have with an outstanding principal amount in excess of $15 million.
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
Our future level of debt could have important consequences to us, including the following:
| • | our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including required drilling pad connections and well connections pursuant to our gas gathering agreements as well as acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms; |
| • | our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt; |
| • | we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and |
| • | our flexibility in responding to changing business and economic conditions may be limited. |
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.
The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.
Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.
Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price will be impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in 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.
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Due to our lack of industry and geographic diversification, adverse developments in our existing areas of operation could adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.
Our operations are focused on natural gas gathering, treating and compression services, and our assets are principally located in our Barnett Shale region in north-central Texas, our Haynesville Shale region in northwest Louisiana and our Mid-Continent region in Oklahoma, Texas, Arkansas and Kansas. As a result, our financial condition, results of operations and cash flows depend upon the demand for our services in these regions. Due to our lack of diversification in industry type and geographic location, adverse developments in our current segment of the midstream industry or our existing areas of operation could have a significantly greater impact on our financial condition, results of operations and cash flows than if our operations were more diversified. In particular, a significant portion of our operations and growth strategy are concentrated in the Barnett Shale region, which could disproportionately expose us to operational and regulatory risk in that area. The location of the Barnett Shale in the Dallas-Fort Worth, Texas metropolitan area poses unique challenges associated with drilling for natural gas in urban and suburban communities. State and local regulations regarding the operation of drilling rigs limit the number of potential new drilling sites that can be used for infill drilling programs.
Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.
An increasing percentage of our customers’ oil and gas production is being developed from unconventional sources, such as deep gas shales. These reservoirs require hydraulic fracturing completion processes to release the gas from the rock so it can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. The EPA, has commenced a study of the potential environmental impacts of hydraulic fracturing activities. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress to provide for such regulation. We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through our gathering systems which would materially adversely affect our revenues and results of operations.
We may incur significant costs and liabilities in complying with, or as a result of a failure to comply with, new or existing environmental laws and regulations, and changes in environmental laws or regulations could adversely impact our customers’ production and operations, which could have a material adverse effect on our results of operations and cash flows.
Our natural gas gathering, treating and compression operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations, including obtaining permits to conduct regulated activities, incurring capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and imposing substantial liabilities and remedial obligations relating to pollution or emissions that may result from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring 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.
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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, the Texas Commission on Environmental Quality has recently adopted new rules governing emissions of regulated pollutants from oil and natural gas facilities and continues to evaluate existing air regulations and proposed revisions to existing regulations as well as seek to promulgate new regulations that meet or exceed federal requirements. Such revised or new rules would establish new limits on emissions from some of our facilities as well as require implementation of best practices and/or technology and new monitoring and record keeping requirements. Similar regulatory changes could lead to more stringent air permitting, increased regulation and possible enforcement actions against the regulated community. Additionally, the EPA has recently entered into a settlement that requires it to consider strengthening revisions to regulations under the Clean Air Act, including the New Source Performance Standards, Maximum Achievable Control Technology standards and residual risk standards, affecting a wide array of air emission sources in the natural gas industry. If these or other initiatives result in an increase in regulation, it could increase our costs or reduce our customers’ production, which could have a material adverse effect on our results of operations and cash flows.
There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry practices, our handling of hydrocarbon wastes and air emissions and discharges related to our operations. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may not be able to recover all or any of these costs from insurance.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas services we provide.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air 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. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including certain natural gas processing facilities, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. 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.
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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 the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act (“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 initial term of the provision of general and administrative services by Chesapeake under the services agreement will continue until December 31, 2011 and will extend for additional twelve-month periods unless we or Chesapeake provides 180 days’ prior written notice of termination, subject to certain conditions and limitations. Notwithstanding the foregoing, we have the right to unilaterally extend the provision by Chesapeake of the general and administrative services through June 30, 2012. 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.
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If we fail to develop or 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 GAAP, but our internal accounting controls may not currently 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 develop and 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 will require 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 must comply with Section 404 for our fiscal year ending December 31, 2011. Any failure to develop, implement or 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, and we may incur significant costs in our efforts to comply with Section 404. 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
Chesapeake and GIP, through their joint ownership of Chesapeake Midstream Ventures, indirectly own and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Chesapeake, GIP and Chesapeake Midstream Ventures, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our common unitholders.
Chesapeake Midstream Ventures, which is owned and controlled by Chesapeake and GIP, owns and controls our general partner and appoints all of the officers and directors of our general partner, some of whom are also officers and directors of Chesapeake, GIP and/or Chesapeake Midstream Ventures. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, Chesapeake Midstream Ventures. Conflicts of interest will arise between Chesapeake, GIP, Chesapeake Midstream Ventures and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Chesapeake, GIP and/or Chesapeake Midstream Ventures over our interests and the interests of our common unitholders. These conflicts include the following situations, among others:
| • | Neither our partnership agreement nor any other agreement requires Chesapeake, GIP or Chesapeake Midstream Ventures to pursue a business strategy that favors us. |
| • | Our general partner is allowed to take into account the interests of parties other than us, such as Chesapeake, GIP or Chesapeake Midstream Ventures, in resolving conflicts of interest. |
| • | The chief executive officer of our general partner will also devote significant time to the business of Chesapeake and will be compensated by Chesapeake accordingly. |
| • | Our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. |
| • | Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval. |
| • | Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders. |
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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. |
| • | Our general partner determines which costs incurred by it are reimbursable by us. |
| • | Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period. |
| • | Our partnership agreement permits us to classify up to $120 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights. |
| • | Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf. |
| • | Our general partner intends to limit its liability regarding our contractual and other obligations. |
| • | Disputes may arise under our gas gathering agreement with Chesapeake, including with respect to fee redeterminations or the determination of amounts payable as liquidated damages upon Chesapeake’s failure, if any, to meet its minimum volume commitments under the agreement. |
| • | Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80 percent of the common units. |
| • | Our general partner controls the enforcement of the obligations that it and its affiliates owe to us. |
| • | Our general partner decides whether to retain separate counsel, accountants or others to perform services for us. |
| • | Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations. |
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our amended 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.
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Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.
Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
| • | how to allocate business opportunities among us and its affiliates; |
| • | whether to exercise its limited call right; |
| • | how to exercise its voting rights with respect to the units it owns; |
| • | whether to elect to reset target distribution levels; and |
| • | whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement. |
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above.
Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:
| • | provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity; |
| • | provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in the best interest of our partnership; |
| • | provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and |
| • | 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. |
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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 is comprised of seven members, two of whom have been designated by Chesapeake, two of whom have been designated by GIP and three of whom are independent. Chesapeake Midstream Ventures is the sole member of our general partner and has the right to appoint our general partner’s entire board of directors, including our three independent directors. If the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
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Even if holders of our common units are dissatisfied, they cannot remove our general partner currently without Chesapeake and GIP’s consent.
Our unitholders are currently unable to remove our general partner because our general partner and its affiliates own sufficient units to prevent its removal. The vote of the holders of at least 66 2/3 percent of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. As of March 11, 2011, Chesapeake and GIP own an aggregate of 82.3 percent of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and no units held by the holders of the subordinated units or their affiliates are voted in favor of that removal, all subordinated units held by our general partner and its affiliates will automatically be converted into common units. If no units held by any holder of subordinated units or its affiliates are voted in favor of that removal, all subordinated units will convert automatically into common units and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.
Our partnership agreement restricts the voting rights of unitholders owning 20 percent or more of our common units.
Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner, its affiliates, their direct transferees and their indirect transferees approved by our general partner (which approval may be granted in its sole discretion) and persons who acquired such units with the prior approval of our general partner, cannot vote on any matter.
Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Chesapeake Midstream Ventures to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.
Our general partner is jointly owned and controlled indirectly by Chesapeake and GIP. As a result, there is a possibility of deadlocks occurring with respect to important governance or other business decisions affecting us to be made by our general partner, which could adversely affect our business.
Our general partner has sole responsibility for conducting our business and for managing our operations and is controlled by its sole member, Chesapeake Midstream Ventures. As of March 11, 2011, Chesapeake and GIP each directly own a 50 percent membership interest in, and jointly control, Chesapeake Midstream Ventures. Chesapeake Midstream Ventures has the right to appoint our general partner’s entire board of directors, including our three independent directors. We expect that conflicts will arise in the future between Chesapeake, on the one hand, and GIP, on the other hand, with regard to our governance, business and operations. Important governance or other business decisions could be delayed as a result of a deadlock between Chesapeake and GIP, which could adversely affect our business.
We may issue additional units without your approval, which would dilute your existing ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
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| • | our existing unitholders’ proportionate ownership interest in us will decrease; |
| • | the amount of cash available for distribution on each unit may decrease; |
| • | because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; |
| • | the ratio of taxable income to distributions may increase; |
| • | the relative voting strength of each previously outstanding unit may be diminished; and |
| • | the market price of the common units may decline. |
Chesapeake and GIP may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
As of March 11, 2011, Chesapeake and GIP hold an aggregate of 44,638,622 common units and 69,076,122 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. Additionally, we have agreed to provide each of Chesapeake and GIP with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.
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 March 11, 2011, Chesapeake and GIP own an aggregate of approximately 65 percent (exclusive of subordinated units) of our outstanding common units. At the end of the subordination period (which could occur as early as June 30, 2011), assuming no additional issuances of common units (other than upon the conversion of the subordinated units), Chesapeake and GIP will own an aggregate of approximately 82 percent of our outstanding common units, enabling the general partner to exercise the call right at such time.
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:
| • | we were conducting business in a state but had not complied with that particular state’s partnership statute; or |
| • | your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business. |
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Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act ( “Delaware Act”) we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
We incur increased costs as a result of being a publicly traded partnership.
We had no history operating as a publicly traded partnership prior to our IPO. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the New York Stock Exchange (“NYSE”) have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, our cash available for distribution to you would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (“IRS”) on this or any other tax matter affecting us. Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35 percent, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to you.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax each year at a maximum effective rate of 0.7 percent of our gross income apportioned to Texas in the prior year. Imposition of any such taxes may substantially reduce the cash available for distribution to you and, therefore, negatively impact the value of an investment in our common units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
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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, members of Congress have recently considered substantive changes to the existing federal income tax laws that would have affected certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the legislation considered would not have appeared to affect our tax treatment as a partnership, we are unable to predict whether any similar changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
Because our unitholders are treated as partners in us for federal income tax purposes, we will allocate a share of our taxable income to you which could be different in amount than the cash we distribute, and you may be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you do not receive any cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest 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.
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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 first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. 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.
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The sale or exchange of 50 percent or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50 percent threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one calendar year. Our termination could also result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.
As a result of investing in our common units, you may become subject to state, local and non-U.S. taxes and return filing requirements in jurisdictions where we operate or own or acquire property.
In addition to federal income taxes, you will likely be subject to other taxes, including non-U.S., state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file non-U.S., state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We own assets and conduct business in Arkansas, Kansas, Louisiana, Oklahoma and Texas. 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. | Unresolved Staff Comments |
None.
| ITEM 2. | Properties |
Substantially all of our pipelines, which are located in Texas, Louisiana, Oklahoma, Kansas and Arkansas, are constructed on rights of way granted by the apparent record owners of the property. Lands over which pipeline rights of way have been obtained may be subject to prior liens that have not been subordinated to the right of way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways. In some cases, properties on which our pipelines were built were purchased.
We believe we have satisfactory title to all of our assets. Record title to some of our assets may continue to be held by prior owners until we have made the appropriate filings in the jurisdictions in which such assets are located. Obligations under our credit facility are secured by substantially all of our assets and are guaranteed by the Partnership. Title to our assets may also be subject to other encumbrances. We believe that none of such encumbrances should materially detract from the value of our properties or our interest in those properties or should materially interfere with our use of them in the operation of our business.
Our executive offices are located in an office building located at 900 N.W. 63rd Street, Oklahoma City, Oklahoma, under a lease with Chesapeake that expires December 31, 2011, with annual renewal options. We also maintain a regional headquarters located on leased premises in Fort Worth, Texas, under a lease with Chesapeake that expires October 1, 2011, with renewal options through October 1, 2021. We also maintain regional offices located on leased premises in Texas and Oklahoma. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future and that additional office space will be available on commercially reasonable terms as needed.
For additional information regarding our properties, please read “Item 1 – Business.”
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| 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. | (Removed and Reserved) |
| 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 New York Stock Exchange under the symbol “CHKM.” Our common units began trading on July 29, 2010 at an initial offering price of $21.00 per unit. Prior to July 29, 2010, our equity securities were not listed on any exchange or traded in any public market. The following table sets forth the high and low sales prices of the common units as well as the amount of cash distributions declared and paid during each quarter since our IPO.
| Quarter Ended | ||||||||
| December 31, 2010 |
September 30, 2010 |
|||||||
| High Price |
$ | 29.15 | $ | 26.00 | ||||
| Low Price |
$ | 25.20 | $ | 21.25 | ||||
| Distribution per common and subordinated unit |
$ | 0.3375 | $ | 0.2165 | ||||
As of March 1, 2011, there were approximately 11 unitholders of record of the Partnership’s common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. We have also issued 69,076,122 subordinated units and 2,819,434 general partner units, for which there is no established public trading market. All of the subordinated units and general partner units are held by affiliates of our general partner. Our general partner and its affiliates receive quarterly distributions on these units only after sufficient funds have been paid to the common units.
Use of Proceeds from Sale of Securities
On August 3, 2010, we completed our IPO of 24,437,500 common units, including 3,187,500 common units sold pursuant to the exercise by the underwriters of their over-allotment option to purchase additional common units at a price of $21.00 per unit. In connection with the IPO, we issued to our general partner 2,819,434 general partner units and 100 percent of our IDRs, which entitle our general partner to increasing percentages up to a maximum of 50.0 percent of cash distributions based on the amount of the quarterly cash distribution. We also issued 23,913,061 and 20,725,561 common units and 34,538,061 subordinated units each to Chesapeake and GIP, respectively. Upon completion of the IPO, Chesapeake and GIP conveyed to us a 100 percent membership interest in Chesapeake MLP Operating, L.L.C., which owned all of our assets since September 2009.
The Partnership received gross offering proceeds of approximately $513.2 million less approximately $38.6 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of the contribution agreement, the Partnership distributed the approximate $62.4 million of net proceeds from the exercise of the over-allotment option to GIP on August 3, 2010. The Partnership used the net offering proceeds of $412.2 million to repay approximately $110.0 million of borrowings under its revolving credit facility and to pay approximately $5.1 million of fees related to the amendment of its revolving credit facility. The remainder was used to fund expansion capital expenditures (see definition of expansion capital expenditures under the heading “Capital Requirements” in Part II, Item 7 of this Form 10-K) and part of the Springridge acquisition.
Selected Information from our Partnership Agreement
Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions, minimum quarterly distributions and IDRs.
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Available cash
Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending September 30, 2010, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, including reserves to fund future capital expenditures, to comply with applicable laws, or our debt instruments and other agreements, or to provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement.
Minimum Quarterly Distribution
The partnership agreement provides that, during the Subordination Period, the common units are entitled to distributions of available cash each quarter in an amount equal to the minimum quarterly distribution, which is $0.3375 per common unit, 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 $0.3375 per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2013. Also, if the Partnership has earned and paid at least 150 percent of the minimum quarterly distribution on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the Subordination Period will terminate automatically. The Subordination Period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of removal. When the Subordination Period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages. All subordinated units are held indirectly by Chesapeake and GIP.
General Partner Interest and Incentive Distribution Rights
Our general partner is entitled to two percent of all quarterly distributions that we make after inception and prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its two percent general partner interest. Our general partner’s interest in our distributions may be reduced if we issue additional limited partner units in the future, other than the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the IDRs) and our general partner does not contribute a proportionate amount of capital to us to maintain its two percent general partner interest.
Other Securities Matters
Securities Authorized for Issuance Under Equity Compensation Plans.
In connection with the closing of our IPO, our general partner adopted the Chesapeake Midstream Long-Term Incentive Plan, or “LTIP,” which permits the issuance of up to 3,500,000 units, subject to adjustment for certain events. Phantom unit grants have been made to each of the independent directors of our general partner under the LTIP. Please read the information under Item 12 of this annual report, which is incorporated by reference into this Item 5.
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ITEM 6. Selected Financial Data
The following table shows our selected financial and operating data for the periods and as of the dates indicated, which is derived from our consolidated financial statements. On August 3, 2010, we closed our IPO of 24,437,500 common units, including 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option. Upon completion of the IPO, Chesapeake and GIP contributed to us Chesapeake MLP Operating, L.L.C., which owned all of our assets since September 2009. On December 21, 2010, we closed on the Springridge acquisition with Chesapeake.
The table should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements, including the notes, appearing in Items 7 and 8 of this Annual Report.
| Predecessor | ||||||||||||||||||||||||||
| Year Ended December 31, 2010 |
Three Months Ended December 31, 2009 |
Nine Months Ended September 30, 2009 |
Year Ended December 31, 2008 |
Year Ended December 31, 2007 |
Year Ended December 31, 2006 |
|||||||||||||||||||||
| Statement of Operations Data: |
($ in thousands) | |||||||||||||||||||||||||
| Revenues(1) |
$ | 459,153 | $ | 107,377 | $ | 358,921 | $ | 332,783 | $ | 191,931 | $ | 100,590 | ||||||||||||||
| Operating expenses |
133,293 | 31,874 | 146,604 | 141,803 | 77,589 | 34,914 | ||||||||||||||||||||
| Depreciation and amortization expense |
93,477 | 20,699 | 65,477 | 47,558 | 24,505 | 9,761 | ||||||||||||||||||||
| General and administrative expense |
31,992 | 2,854 | 22,782 | 13,362 | 6,880 | 2,766 | ||||||||||||||||||||
| Impairment of property, plant and equipment and other assets(2) |
— | — | 90,207 | 30,000 | — | — | ||||||||||||||||||||
| (Gain) loss on sale of assets(3) |
285 | 34 | 44,566 | (5,541 | ) | — | — | |||||||||||||||||||
| Total operating expenses |
259,047 | 55,461 | 369,636 | 227,182 | 108,974 | 47,441 | ||||||||||||||||||||
| Operating income (loss) |
200,106 | 51,916 | (10,715 | ) | 105,601 | 82,957 | 53,149 | |||||||||||||||||||
| Interest expense |
(2,550 | ) | (619 | ) | (347 | ) | (1,871 | ) | — | — | ||||||||||||||||
| Other income |
102 | 34 | 29 | 278 | — | — | ||||||||||||||||||||
| Income (loss) before income taxes |
197,658 | 51,331 | (11,033 | ) | 104,008 | 82,957 | 53,149 | |||||||||||||||||||
| Income tax expense (benefit)(4) |
2,431 | 639 | 6,341 | (61,287 | ) | 31,109 | 19,931 | |||||||||||||||||||
| Net income (loss) |
$ | 195,227 | $ | 50,692 | $ | (17,374 | ) | $ | 165,295 | $ | 51,848 | $ | 33,218 | |||||||||||||
| Net income per common unit – basic and diluted(5) |
$ | 0.78 | n/a | n/a | n/a | n/a | n/a | |||||||||||||||||||
| Net income per subordinated unit – basic and diluted(5) |
$ | 0.78 | n/a | n/a | n/a | n/a | n/a | |||||||||||||||||||
| Distribution per unit |
$ | 0.55 | n/a | n/a | n/a | n/a | n/a | |||||||||||||||||||
| Balance Sheet Data (at period end): |
||||||||||||||||||||||||||
| Net property, plant and equipment |
$ | 2,226,909 | $ | 1,776,415 | $ | 2,870,547 | $ | 2,339,473 | $ | 965,801 | $ | 381,090 | ||||||||||||||
| Total assets |
2,545,916 | 1,958,675 | 3,232,840 | 2,583,765 | 1,010,112 | 403,141 | ||||||||||||||||||||
| Revolving bank credit facility |
249,100 | 44,100 | 12,173 | 460,000 | — | — | ||||||||||||||||||||
| Total equity |
2,194,568 | 1,793,627 | 2,996,403 | 1,793,269 | 847,421 | 325,951 | ||||||||||||||||||||
| Cash Flow Data: |
||||||||||||||||||||||||||
| Net cash provided by (used in): |
||||||||||||||||||||||||||
| Operating activities |
$ | 317,091 | $ | 14,730 | $ | 100,748 | $ | 236,774 | $ | 93,948 | $ | 55,587 | ||||||||||||||
| Investing activities |
(711,480 | ) | (46,352 | ) | (690,994 | ) | (1,384,834 | ) | (563,564 | ) | (218,843 | ) | ||||||||||||||
| Financing activities stock |
412,202 | 31,590 | 664,268 | 1,230,059 | 469,622 | 163,272 | ||||||||||||||||||||
| Key Performance Metrics: |
||||||||||||||||||||||||||
| Adjusted EBITDA(6) |
$ | 293,970 | $ | 72,683 | $ | 189,564 | $ | 177,896 | $ | 107,462 | ||||||||||||||||
| Distributable cash flow |
218,989 | n/a | n/a | n/a | n/a | |||||||||||||||||||||
| Capital expenditures |
216,303 | 46,377 | 756,883 | 1,402,449 | 563,564 | |||||||||||||||||||||
| Operational Data: |
||||||||||||||||||||||||||
| Throughput, Bcf/d |
1.595 | 1.550 | 2.108 | 1.585 | 1.018 | 0.588 | ||||||||||||||||||||
| (1) | 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 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. |
| (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 a $86.2 million income tax benefit in 2008 at the time the change in legal structure occurred. This benefit was partially offset by income tax expense of $24.9 million, resulting in a net income tax benefit of $61.3 million for the year ended December 31, 2008. The income tax expense of $6.3 million for the nine months ended September 30, 2009 is related to our Predecessor’s remaining taxable entity that was not contributed to us. For the year ended December 31, 2010, and the three months ended September 30, 2009, the income tax expense of $2.4 million and $0.6 million, respectively, is entirely related to Texas Franchise Tax. |
| (5) | Reflective of limited partner interest in net income since closing the Partnership’s IPO on August 3, 2010. See Note 4 to the consolidated financial statements in Item 8 of this annual report. |
| (6) | Adjusted EBITDA and distributable cash flow are defined under the heading Adjusted EBITDA and Distributable Cash Flow in Item 7 of this annual report. For reconciliations of Adjusted EBITDA and distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principals, see How We Evaluate Our Operations in Item 7 of this annual report. |
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| ITEM 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Unless the context otherwise requires, references in this report to the “Partnership,” “we,” “our,” “us” or like terms, when used in a historical context, refer to the financial results of Chesapeake Midstream Partners, L.L.C. from its inception on September 30, 2009 through the closing date of our initial public offering (“IPO”) on August 3, 2010 and to Chesapeake Midstream Partners, L.P. and its subsidiaries thereafter. “Predecessor” refers to Chesapeake Midstream Development, L.P. which held substantially all of our assets as well as other midstream assets prior to September 30, 2009. “Chesapeake” refers to Chesapeake Energy Corporation (NYSE: CHK) and “GIP” refers to Global Infrastructure Partners – A, L.P., and affiliated funds managed by Global Infrastructure Management, L.L.C., and certain of their respective subsidiaries and affiliates. “Total”, when discussing the upstream joint venture with Chesapeake, refers to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (NYSE: TOT, FP: FP), and when discussing our gas gathering agreement and related matters, refers to Total E&P USA, Inc. and Total Gas & Power North America, Inc., a wholly owned subsidiary of Total S.A.
Overview
We are a growth-oriented publicly-traded Delaware limited partnership formed by Chesapeake and GIP to own, operate, develop and acquire natural gas gathering systems and other midstream energy assets. We are principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. We currently operate in Texas, Louisiana, Oklahoma, Kansas and Arkansas. We provide gathering, treating and compression services to Chesapeake and Total, our primary customers, and other third-party producers under long-term, fixed-fee contracts.
Initial Public Offering
On August 3, 2010, we completed our IPO of 24,437,500 common units (amount includes 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option on August 3, 2010) at a price of $21.00 per unit. We received gross offering proceeds of approximately $513.2 million less approximately $38.6 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of the contribution agreement, we distributed the approximate $62.4 million of net proceeds from the exercise of the over-allotment option to GIP on August 3, 2010. Upon completion of the IPO, we had outstanding 69,076,122 common units, 69,076,122 subordinated units, a 2 percent general partner interest and incentive distribution rights (“IDRs”). IDRs entitle the holder to specified increasing percentages of cash distributions as the Partnership’s per-unit cash distributions increase above specified levels. Upon completion of the IPO, common units held by the public represented 17.7 percent of all outstanding limited partner interests, and Chesapeake and GIP held 42.3 percent and 40.0 percent, respectively, of all outstanding limited partner interests.
Springridge Gathering System Acquisition
On December 21, 2010, we acquired the Springridge gathering system and related facilities from Chesapeake Midstream Development, L.P., a wholly owned subsidiary of Chesapeake, for $500 million. The Springridge gathering system consists of 226 miles of gathering pipeline primarily located in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, we entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication, annual fee redetermination and a three-year minimum volume commitment.
The acquisition was financed with a draw on the Partnership’s revolving credit facility of approximately $234.0 million plus approximately $266.0 million of cash on hand. The results of operations presented and discussed in this Item 7 include results of operations from the Springridge gathering system for the 11-day period from closing of the acquisition on December 21, 2010, through December 31, 2010, including associated transaction costs.
Our Operations
Our gathering systems operate in our Barnett Shale region in north-central Texas, our Haynesville Shale region in northwest Louisiana and our Mid-Continent region, which includes the Anadarko, Arkoma, Delaware and Permian Basins. We generate the majority of our operating income in our Barnett Shale region, where we service approximately 1,840 wells in the core of the Barnett Shale. In our Mid-Continent region, we have an enhanced focus on the unconventional resources located in the Colony Granite Wash and Texas Panhandle Granite Wash plays of the Anadarko Basin. In total, our systems consist of approximately 3,370 miles of gathering pipelines, servicing approximately 4,360 natural gas wells. For the year ended December 31, 2010, our assets gathered approximately 1.6 billion cubic feet (“Bcf”) of natural gas per day. Following the acquisition of the Springridge gathering system in December 2010, our assets gathered approximately 2.0 Bcf per day.
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We generated approximately 78 percent of our revenues from our gathering systems in our Barnett Shale region and approximately 22 percent of our revenues from our gathering systems in our Mid-Continent region for the year ended December 31, 2010. The Springridge gathering system contributed to our revenues during the 11 day period from closing of the acquisition to December 31, 2010, but the impact was immaterial to our results.
The results of our operations are primarily driven by the volumes of natural gas we gather, treat and compress across our gathering systems. We currently provide all of our gathering, treating and compression services pursuant to fixed fee contracts, which limit our direct commodity price exposure, and we generally do not take title to the natural gas we gather. We have entered into long-term gas gathering agreements with Chesapeake and Total. Pursuant to our gas gathering agreements, Chesapeake and Total have agreed to dedicate extensive acreage in our Barnett Shale region and Chesapeake has agreed to dedicate extensive acreage in our Haynesville Shale and Mid-Continent regions. These agreements generally require us to connect Chesapeake and Total operated natural gas drilling pads and wells within our acreage dedications to our gathering systems and contain the following terms that are intended to support the stability of our cash flows: (i) minimum volume commitments for 10 years in our Barnett Shale region and three years in our Haynesville Shale region, which mitigate throughput volume variability; (ii) fee redetermination mechanisms in our Barnett Shale, Haynesville Shale and Mid-Continent regions, which are designed to support a return on our invested capital and allow our gathering rates to be adjusted, subject to specified caps, to account for variability in revenues, capital expenditures and compression expenses; and (iii) price escalators in our Barnett Shale, Haynesville Shale and Mid-Continent regions, which annually increase our gathering rates.
Our Gas Gathering Agreements
We are party to (i) a 20-year gas gathering agreement with certain subsidiaries of Chesapeake that was entered into in connection with the joint venture transaction in September 2009, (ii) a 20-year gas gathering agreement with Total that was entered into in connection with an upstream joint venture transaction between Chesapeake and Total E&P in January 2010, and (iii) a 10-year gas gathering agreement with certain subsidiaries of Chesapeake that was entered into concurrent with the closing of the acquisition of the Springridge gas gathering system in December 2010.
Future revenues under our gas gathering agreements will be derived pursuant to terms that will differ between our three operating regions. The following outlines the key economic provisions of our gas gathering agreements by region.
Barnett Shale Region. Under our gas gathering agreements with Chesapeake and Total, we have agreed to provide the following services in our Barnett Shale region for the fees and obligations outlined below:
| • | Gathering, Treating and Compression Services. We gather, treat and compress natural gas for Chesapeake and Total within the Barnett Shale region in exchange for specified fees per 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, which we refer to as the Barnett Shale fee. Our Barnett Shale fee is subject to an annual rate escalation ranging between 2.0 percent and 2.5 percent at the beginning of each year. |
| • | Acreage Dedication. Pursuant to our gas gathering agreements, subject to certain exceptions, each of Chesapeake and Total has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on natural gas and oil leases covering lands within an acreage dedication in our Barnett Shale region. |
| • | 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 will be attributed to Chesapeake, and approximately 25 percent will be 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: |
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| (1) | Includes a one-time carry forward of approximately 20 Bcf, which was carried forward from the minimum volume commitment for the six months ended December 31, 2009. |
| (2) | Indicated volumes relate to the six months ending June 30, 2019. |
In the event either Chesapeake or Total does not meet its minimum volume commitment to us, as adjusted in certain instances, for any annual period (or six-month period in the case of the six months ending June 30, 2019) during the minimum volume commitment period, Chesapeake or Total will be obligated to pay us a fee equal to the Barnett Shale fee for each Mcf by which the applicable party’s minimum volume commitment for the year (or six-month period) exceeds the actual volumes gathered on our systems attributable to the applicable party’s production. To the extent natural gas gathered on our systems from Chesapeake or Total during any annual period (or six-month period) exceeds such party’s minimum volume commitment for the period, Chesapeake or Total will be obligated to pay us the Barnett Shale fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitments for the six months ending June 30, 2019, and then against the minimum volume commitments of each preceding year. In the event that the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the final day of the immediately preceding period.
| • | Fee Redetermination. We and each of Chesapeake and Total, have the right to redetermine the Barnett Shale fee during a six-month period beginning September 30, 2011 and 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 forecast as of the redetermination date and scheduled estimates thereof 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 do not agree upon a redetermination of the Barnett Shale fee within 30 days of receipt of the request for the redetermination, an industry expert will be selected to determine adjustments to the Barnett Shale fee. |
| • | Well Connection Requirement. Subject to required notice by Chesapeake and Total and certain exceptions, we have generally agreed to connect new operated drilling pads and new operated wells within our Barnett Shale region acreage dedications as requested by Chesapeake and Total during the minimum volume commitment period. During the minimum volume period, if we fail to complete a connection in the acreage dedication by the required date, Chesapeake and Total, as their sole remedy for such delayed connection, are entitled to a delay in the minimum volume obligations for gas volumes that would have been produced from the delayed connection. |
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| • | Fuel, Lost and Unaccounted For Gas. We have agreed with Chesapeake on MMBtu-based caps on fuel, lost and unaccounted for gas on our systems, both on an individual basis and an aggregate basis, with respect to Chesapeake’s volumes. These caps do not apply to certain of our gathering systems due to their historic performance relative to the caps. These systems will be reviewed annually to determine whether changes have occurred that would make them suitable for inclusion. In the event that we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel, lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk. |
Haynesville Shale Region. Under our gas gathering agreement with Chesapeake, we have agreed to provide the following services in our Haynesville Shale region to Chesapeake for the fees and obligations outlined below:
| • | Gathering, Treating and Compression Services. We gather, treat and compress natural gas in exchange for fees per Mcf for natural gas gathered and per Mcf for natural gas compressed, which we refer to as the Springridge fees. The Springridge fees for these systems are subject to an annual specified rate escalation at the beginning of each year. |
| • | Minimum Volume Commitments. Pursuant to our gas gathering agreement, Chesapeake has agreed to minimum volume commitments for each year through December 31, 2013. In the event Chesapeake does not meet its minimum volume commitment to us, as adjusted in certain instances, for any annual period during the minimum volume commitment period, Chesapeake will be obligated to pay us a fee equal to the Springridge fee for each Mcf by which the minimum volume commitment for the year exceeds the actual volumes gathered on our systems attributable to Chesapeake’s production. To the extent natural gas gathered on our systems from Chesapeake during any annual period exceeds Chesapeake’s minimum volume commitment for the period, Chesapeake will be obligated to pay us the Springridge fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitments for the year 2013, and then against the minimum volume commitments of each preceding year. In the event that the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the final day of the immediately preceding period. |
| • | Acreage Dedication. Pursuant to our gas gathering agreement, subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on oil, natural gas and mineral leases within the Springridge acreage dedication. |
| • | Fee Redetermination. The Springridge fees are subject to a redetermination mechanism. The first redetermination period will extend from December 1, 2010 through December 31, 2012, and subsequent redetermination periods will be the calendar years 2013 through 2020. We will determine an adjustment to fees for the gathering systems in the region with Chesapeake based on the factors specified in the gas gathering agreement, including, but not limited to, differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the period ending December 31, 2020, referred to as the redetermination period, made as of November 30, 2010. The annual upward or downward fee adjustment for the Springridge region is capped at 15 percent of the then current fees at the time of redetermination. |
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| • | Well Connection Requirement. We have certain connection obligations for new operated drilling pads and operated wells of Chesapeake in the acreage dedications. Chesapeake is required to provide us notice of new drilling pads and wells operated by Chesapeake in the acreage dedications. Subject to certain conditions specified in the gas gathering agreement, we are generally required to connect new operated drilling pads in the acreage dedication by the later of 30 days after the date the wells commence production or six months after the date of the connection notice. During the minimum volume period, if we fail to complete a connection in the Springridge acreage dedication by the required date, Chesapeake, as its sole remedy for such delayed connection, is entitled to a delay in the minimum volume obligations for gas volumes that would have been produced from the delayed connection. After the minimum volume period, we are subject to a daily penalty for such delayed connections, up to a specified cap per delayed connection. Chesapeake also is required to notify us of its wells drilled in the acreage dedications that are operated by other parties and we have the option, but not the obligation, to connect non-operated wells to our gathering systems. If we decline to make a connection to a non-operated well, Chesapeake has certain rights to have the well released from the dedication under the gas gathering agreement. |
Mid-Continent Region. Under our gas gathering agreement with Chesapeake, we have agreed to provide the following services in our Mid-Continent region to Chesapeake for the fees and obligations of Chesapeake outlined below:
| • | Gathering, Treating and Compression Services. We gather, treat and compress natural gas in exchange for system-based services fees per Mcf for natural gas gathered and per Mcf for natural gas compressed, which we refer to as the Mid-Continent fees. The Mid-Continent fees for these systems are subject to an annual 2.5 percent rate escalation at the beginning of each year. |
| • | Acreage Dedication. Pursuant to our gas gathering agreement, subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on oil, natural gas and mineral leases covering lands within the acreage dedication. |
| • | Fee Redetermination. The Mid-Continent fees will be redetermined at the beginning of each year through 2019. We will determine an adjustment to fees for the gathering systems in the region with Chesapeake based on the factors specified in the gas gathering agreement, including, but not limited to, differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the period ending June 30, 2019, referred to as the redetermination period, made as of September 30, 2009. The annual upward or downward fee adjustment for the Mid-Continent region is capped at 15 percent of the then current fees at the time of redetermination. |
| • | Well Connection Requirement. Subject to required notice by Chesapeake and certain exceptions, we have generally agreed to use our commercially reasonable efforts to connect new operated drilling pads and new operated wells in our Mid-Continent region acreage dedications as requested by Chesapeake through June 30, 2019. |
| • | Fuel, Lost and Unaccounted For Gas. We have agreed with Chesapeake on MMBtu-based caps on fuel, lost and unaccounted for gas on certain of our systems, both on an individual basis and an aggregate basis, with respect to Chesapeake’s volumes. These caps do not apply to certain of our gathering systems due to their historic performance relative to the caps. These systems will be reviewed annually to determine whether changes have occurred that would make them suitable for inclusion. In the event that we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel, lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk. |
We believe the recent trend of producers moving drilling rigs from dry gas regions to liquids rich plays such as the Mid-Continent may present an opportunity for us to enter the market of gathering and transporting oil as we believe those services fit well with our current business model.
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In the event that either Chesapeake or Total sells, transfers or otherwise disposes to a third party properties within the acreage dedication in our Barnett Shale region and, solely with respect to Chesapeake in our Haynesville Shale region and our Mid-Continent region, it will be required to cause the third party to either enter into our existing gas gathering agreement with Chesapeake or Total or enter into a new gas gathering agreement with us on substantially similar terms to our existing gas gathering agreement with Chesapeake or Total.
Other Arrangements
Business Opportunities. Pursuant to our services agreement with Chesapeake, Chesapeake has agreed to provide us a right of first offer with respect to three specified categories of transactions: (i) opportunities to develop or invest in midstream energy projects within five miles of our acreage dedications, (ii) opportunities to succeed third parties in expiring midstream energy service contracts within five miles of the acreage dedications and (iii) opportunities with respect to future midstream divestitures outside of the acreage dedications. The consummation, if any, and timing of any such future transactions will depend upon, among other things, our ability to reach an agreement with Chesapeake and our ability to obtain financing on acceptable terms. Notwithstanding the foregoing, Chesapeake is under no obligation to accept any offer made by us with respect to such opportunities. Although we will have certain rights with respect to the potential business opportunities, we are not under any contractual obligation to pursue any such transactions. Chesapeake and its affiliates will not be required to provide us with a right of first offer with respect to the following types of transactions:
| • | equity financing transactions by Chesapeake in respect of any midstream gathering systems and/or associated infrastructure located outside of the acreage dedications and the proximate areas, the net proceeds of which are used to finance the construction, development and/or operation of such midstream gathering systems and/or associated infrastructure assets; |
| • | any financing transactions consisting of debt that is non-convertible and non-exchangeable, provided that any such transaction or series of related transactions may include the issuance of equity interests to the parties providing financing or affiliates thereof that in the aggregate constitute less than 20% of the aggregate value of such financing transaction; |
| • | any transactions that would result in a change of control of Chesapeake Energy Corporation or a sale of all or substantially all of the assets of Chesapeake Energy Corporation and its subsidiaries, taken as a whole; |
| • | any sale, joint venture or other monetization of any midstream gathering system and/or associated infrastructure assets outside the acreage dedications and the proximate areas in connection with a sale of interests in oil and gas properties (including, but not limited to, volumetric production payments) in which the majority of the assets (by value) are comprised of oil and gas exploration and production assets; |
| • | any transaction that was subject to a right of first refusal, purchase or similar commitment to a third party as of September 30, 2009; |
| • | any exchange, swap or similar property-for-property transaction involving the exchange of any midstream gathering system and/or associated infrastructure assets outside the acreage dedications and the proximate areas for other midstream gathering systems and/or associated infrastructure assets outside the acreage dedications and the proximate areas, to the extent any net cash proceeds to Chesapeake from any such transaction or series of related transactions does not comprise more than 20% of the aggregate value of the assets subject to such transaction or series of related transactions; and |
| • | any sale, transfer or disposition to a 100% affiliate of Chesapeake Energy Corporation that remains a 100% affiliate of Chesapeake Energy Corporation at all times following such sale, transfer or disposition. |
With respect to the fifth bullet listed above, a third party has a right of first refusal covering Chesapeake’s midstream assets in the Marcellus Shale that has priority over our right of first offer applicable to any monetization of those assets by Chesapeake.
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 $0.03025 per Mcf multiplied by the volume (measured in Mcf) of natural gas that we gather, treat or compress. The $0.03025 per Mcf cap is subject to an annual upward adjustment on October 1 of each year equal to 50 percent of any increase in the Consumer Price Index, and, subject to receipt of requisite approvals, such cap may be further adjusted to reflect changes in general and administrative services provided by Chesapeake relating to new laws or accounting rules that are implemented. The cap contained in the services agreement does not apply to our direct general and administrative expenses.
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Additionally, pursuant to an employee secondment agreement, specified employees of Chesapeake are seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Our general partner, subject to specified exceptions and limitations, reimburses Chesapeake on a monthly basis for substantially all costs and expenses it incurs relating to such seconded employees. Additionally, under our employee transfer agreement, we are required to maintain certain compensation standards for seconded employees to whom we make offers for hire.
How We Evaluate Our Operations
Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (i) throughput volumes, (ii) revenues, (iii) operating expenses, (iv) Adjusted EBITDA and (v) distributable cash flow.
Throughput Volumes
Although Chesapeake’s and Total’s respective minimum volume commitments generally provide us with protection in the event that throughput volumes from Chesapeake or Total in the Barnett Shale region and Chesapeake in the Haynesville Shale region do not meet certain levels, our management analyzes our performance based on the aggregate amount of throughput volumes on our gathering systems in our Barnett Shale, Haynesville Shale and Mid-Continent regions in order to maintain or increase throughput volumes on our gathering systems as a whole. Our success in connecting additional wells is impacted by successful drilling activity on the acreage dedicated to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage, our ability to attract natural gas volumes currently gathered by our competitors and our ability to cost-effectively construct new infrastructure to connect new wells.
Revenues
Our revenues are driven primarily by our customers’ minimum volume commitments and the actual volumes of natural gas we gather, treat and compress. In the case of our Barnett Shale and Haynesville Shale volumes, our results will be supported by the minimum volume commitments contained in our gas gathering agreements with Chesapeake and Total. We contract with producers to gather natural gas from individual wells located near our gathering systems. We connect wells to gathering pipelines through which natural gas is compressed and may be delivered to a treating facility, processing plant or an intrastate or interstate pipeline for delivery to market. We treat natural gas that we gather to the extent necessary to meet required specifications of third-party takeaway pipelines. For the year ended December 31, 2010, Chesapeake and its working interest partners accounted for approximately 93 percent of the natural gas volumes on our gathering systems and 97 percent of our revenues.
Our revenues are also impacted by other aspects of our contractual agreements, including rate redetermination, and our management constantly evaluates capital spending and its impact on future revenue generation.
Operating Expenses
Our management seeks to maximize the profitability of our operations by minimizing operating expenses while never 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 taxes and other operating costs, some of which are independent of the volumes that flow through our systems but fluctuate depending on the scale of our operations during a specific period.
Chesapeake has extensive operational, commercial, technical and administrative personnel that we plan to utilize to enhance our operating efficiency and overall asset utilization. In some instances, these services are available to us at a low cost compared to the expense of developing these functions internally.
Adjusted EBITDA and Distributable Cash Flow
We define Adjusted EBITDA as net income (loss) before income tax expense (benefit), interest expense, depreciation and amortization expense and certain other items management believes effect the comparability of operating results.
We define distributable cash flow as Adjusted EBITDA, plus interest income, less cash paid for interest expense, maintenance capital expenditures and income taxes. Distributable cash flow does not reflect changes in working capital balances. Distributable cash flow and Adjusted EBITDA are not presentations made in accordance with generally accepted accounting principles (“GAAP”).
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We did not utilize a distributable cash flow measure prior to becoming a publicly traded partnership in 2010 and, as such, did not differentiate between maintenance and capital expenditures prior to 2010 and do not report distributable cash flow for periods prior to 2010.
Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:
| • | our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis, or in the case of Adjusted EBITDA, financing methods; |
| • | our ability to incur and service debt and fund capital expenditures; |
| • | the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and |
| • | the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities. |
Reconciliation to GAAP measures
We believe that the presentation of Adjusted EBITDA and distributable cash flow provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow are net income and net cash provided by operating activities, respectively. 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 measure of Adjusted EBITDA to the GAAP financial measure of net income and a reconciliation of the non-GAAP financial measure of distributable cash flow to the GAAP financial measures of net income and cash provided by operating activities:
| Predecessor | ||||||||||||||||||||
| Year Ended December 31, 2010 |
Three Months Ended December 31, 2009 |
Nine Months Ended September 30, 2009 |
Year Ended December 31, 2008 |
|||||||||||||||||
| ($ in thousands) | ||||||||||||||||||||
| Net Income (loss) |
$ | 195,227 | $ | 50,692 | $ | (17,374 | ) | $ | 165,295 | |||||||||||
| Interest expense |
2,550 | 619 | 347 | 1,871 | ||||||||||||||||
| Income tax expense (benefit) |
2,431 | 639 | 6,341 | (61,287 | ) | |||||||||||||||
| Depreciation and amortization expense |
93,477 | 20,699 | 65,477 | 47,558 | ||||||||||||||||
| Impairment of property, plant and equipment and other assets |
— | — | 90,207 | 30,000 | ||||||||||||||||
| (Gain) Loss on sale of assets |
285 | 34 | 44,566 | (5,541 | ) | |||||||||||||||
| Adjusted EBITDA |
$ | 293,970 | $ | 72,683 | $ | 189,564 | $ | 177,896 | ||||||||||||
| Cash provided by operating activities |
$ | 317,091 | n/a | n/a | n/a | |||||||||||||||
| Changes in assets and liabilities |
(28,002 | ) | n/a | n/a | n/a | |||||||||||||||
| Maintenance capital expenditures |
(70,000 | ) | n/a | n/a | n/a | |||||||||||||||
| Other non-cash items |
(100 | ) | n/a | n/a | n/a | |||||||||||||||
| Distributable cash flow(1) |
$ | 218,989 | n/a | n/a | n/a | |||||||||||||||
| (1) | We did not utilize a distributable cash flow measure prior to becoming a publicly traded partnership in 2010 and, as such, did not differentiate between maintenance and capital expenditures prior to 2010 and do not report distributable cash flow for periods prior to 2010. |
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Items Impacting the Comparability of Our Financial Results
Our current and future results of operations may not be comparable to the historical results of operations for the periods presented for our Predecessor, for the reasons described below:
| • | At December 31, 2010, our assets constituted approximately 79 percent of the total assets of our Predecessor immediately prior to the formation of the joint venture between Chesapeake and GIP on September 30, 2009. |
| • | The historical consolidated financial statements of our Predecessor cover periods in which our assets experienced significant growth. Due to the significant build-out of our gathering systems, capital expenditures by our Predecessor for historical periods presented in the unaudited condensed consolidated financial statements in Part II, Item 8 of this Form 10-K were higher than those we anticipate we will experience in future periods. |
| • | Our Predecessor incurred impairments of property, plant and equipment and other assets of $30.0 million and $90.2 million for the year ended December 31, 2008, and the nine months ended September 30, 2009, respectively. |
| • | We are incurring approximately $2.0 million annually of general and administrative expenses attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and director compensation. These incremental general and administrative expenses are not reflected in the historical consolidated financial statements of our Predecessor. |
| • | We have entered into gas gathering agreements with each of Chesapeake and Total that include fees for gathering, treating and compressing natural gas that are higher than the average fees reflected in our Predecessor’s historical financial results prior to September 30, 2009. In addition, the financial statements subsequent to September 30, 2009, contain revenue associated with minimum volume commitments that did not impact periods prior to September 30, 2009. |
| • | Our Predecessor’s historical consolidated financial statements include U.S. federal and state income tax expense. Due to our status as a partnership, we are not subject to U.S. federal income tax and certain state income taxes. |
| • | We paid a prorated distribution following the quarter ending September 30, 2010, covering the period from the closing of our IPO through September 30, 2010, and paid a quarterly distribution for the three months ended December 31, 2010. Based on the terms of our cash distribution policy, we expect that we will distribute quarterly to our unitholders and our general partner most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations that is not distributed to our unitholders and our general partner, borrowings under our amended revolving credit facility and future issuances of equity and debt securities. Historically, our Predecessor largely relied on internally generated cash flows and capital contributions from Chesapeake to satisfy its capital expenditure requirements. |
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Results of Operations
The results of our operations and those of our Predecessor are not comparable. Please see Items Impacting the Comparability of Our Financial Results in this Item 7. In this discussion, we have presented the factors that materially affected our operating results for the three months ended December 31, 2009 and the full year 2010, and our Predecessor’s operating results in 2008 and for the nine months ended September 30, 2009. A comparative discussion of the results of operations of these periods has not been provided due to the lack of a comparable operating period. The following table and discussion present a summary of our and our Predecessor’s financial results of operations for the periods described above:
| Predecessor | ||||||||||||||||||
| Year Ended December 31, 2010 |
Three Months Ended December 31, 2009 |
Nine Months Ended September 30, 2009 |
Year Ended December 31, 2008 |
|||||||||||||||
| ($ in thousands, except per unit data) | ||||||||||||||||||
| Revenues, including revenue from Affiliates(1) |
$ | 459,153 | $ | 107,377 | $ | 358,921 | $ | 332,783 | ||||||||||
| Operating expenses, including expenses from affiliates |
133,293 | 31,874 | 146,604 | 141,803 | ||||||||||||||
| Depreciation and amortization expense |
93,477 | 20,699 | 65,477 | 47,558 | ||||||||||||||
| General and administrative expense, including expenses from affiliates |
31,992 | 2,854 | 22,782 | 13,362 | ||||||||||||||
| Impairment of property, plant and equipment and other assets |
— | — | 90,207 | 30,000 | ||||||||||||||
| (Gain) Loss on sale of assets |
285 | 34 | 44,566 | (5,541 | ) | |||||||||||||
| Total operating expenses |
259,047 | 55,461 | 369,636 | 227,182 | ||||||||||||||
| Operating income (loss) |
200,106 | 51,916 | (10,715 | ) | 105,601 | |||||||||||||
| Interest expense |
(2,550 | ) | (619 | ) | (347 | ) | (1,871 | ) | ||||||||||
| Other income |
102 | 34 | 29 | 278 | ||||||||||||||
| Income (loss) before income tax expense |
197,658 | 51,331 | (11,033 | ) | 104,008 | |||||||||||||
| Income tax expense (benefit) |
2,431 | 639 | 6,341 | (61,287 | ) | |||||||||||||
| Net income (loss) |
$ | 195,227 | $ | 50,692 | $ | (17,374 | ) | $ | 165,295 | |||||||||
| Operating Data: |
||||||||||||||||||
| Throughput, Bcf/d |
1.595 | 1.550 | 2.108 | 1.585 | ||||||||||||||
| (1) | 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 in the Haynesville Shale region under the applicable gas gathering agreement for specified annual periods, Chesapeake or Total is obligated to pay the Partnership a fee equal to the applicable fee for each mcf by which the applicable party’s minimum volume commitment for the year exceeds the actual volumes gathered on the Partnership’s systems. The Partnership recognizes any associated revenue in the fourth quarter. Our revenues for the three months ended December 31, 2009 includes the impact of $7.7 million attributable to Chesapeake associated with the minimum volume commitment in our Barnett Shale region for 2009. For the year ended December 31, 2010, we recognized revenue related to volume shortfall of $56.8 million, because throughput in our Barnett Shale region was below contractual minimum volume commitment levels. |
Year Ended December 31, 2010
Revenues. Our revenues are primarily attributable to the amount of throughput on our gathering systems and the rates charged for gathering such throughput. For the year ended December 31, 2010, our throughput was 1.6 Bcf per day and revenues were $459.2 million. Because throughput in the Barnett Shale during the year was significantly below contractual minimum volume commitment levels, we recognized revenue related to volume shortfall of $56.8 million. The minimum volume commitment is measured annually and recognized in the fourth quarter of each year.
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The table below reflects revenues and throughput by region for the year ended December 31,2010:
| Revenues | Throughput (Bcf) |
|||||||
| (In thousands, except operational data) | ||||||||
| Barnett Shale |
$ | 358,821 | 374.0 | |||||
| Mid-Continent |
98,250 | 203.4 | ||||||
| Haynesville Shale(1) |
2,082 | 4.9 | ||||||
| $ | 459,153 | 582.3 | ||||||
| (1) | Reflective of revenue and throughput, after completion of the Springridge acquisition, from December 21, 2010, through December 31, 2010. |
Operating Expenses. Operating expenses were $0.23 per Mcf for the year ended December 31, 2010. The table below reflects our total operating expenses and operating expenses per Mcf of throughput by region for the year ended December 31, 2010:
| Operating Expenses |
Expenses ($ per Mcf) |
|||||||
| (In thousands, except per Mcf data) | ||||||||
| Barnett Shale |
$ | 86,927 | $ | 0.23 | ||||
| Mid-Continent |
45,858 | 0.23 | ||||||
| Haynesville Shale(1) |
508 | 0.10 | ||||||
| $ | 133,293 | $ | 0.23 | |||||
| (1) | Reflective of operating expenses, after completion of the Springridge acquisition, from December 21, 2010, through December 31, 2010. |
Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31, 2010 was $93.5 million and primarily related to gathering systems.
General and Administrative Expense. For the year ended December 31, 2010, general and administrative expenses were $32.0 million and were primarily attributable to the expansion of our senior management team, expansion of general and administrative functions in anticipation of functioning as a public company and costs associated with evaluation of acquisition opportunities.
Interest Expense. Interest expense for the year ended December 31, 2010 was $2.6 million, which was net of $2.6 million of capitalized interest. The interest expense is related to borrowings under our revolving credit facility.
Income Tax Expense (Benefit). Income tax expense for the year ended December 31, 2010 was $2.4 million and was attributable to franchise taxes in the state of Texas. The Partnership and its subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the financial statements, other than Texas Franchise Tax.
Three Months Ended December 31, 2009
Revenues. Our revenues are primarily attributable to the amount of throughput on our gathering systems and the rates charged for gathering such throughput. Revenues for the three months ended December 31, 2009 include $7.7 million attributable to Chesapeake associated with the minimum volume commitment in our Barnett Shale region for 2009. Average daily throughput for the Barnett and Mid-Continent was 1.6 Bcf per day for three months ended December 31, 2009. The table below reflects our revenues and throughput by region for the three months ended December 31, 2009:
| Revenues | Throughput (Bcf) |
|||||||
| (In thousands, except operational data) | ||||||||
| Barnett Shale |
$ | 80,880 | 88.3 | |||||
| Mid-Continent |
26,497 | 54.3 | ||||||
| $ | 107,377 | 142.6 | ||||||
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Operating Expenses. Operating expenses for the Barnett and Mid-Continent were $0.22 per Mcf for the three months ended December 31, 2009. The table below reflects our total operating expenses and operating expenses per Mcf of throughput by region for the three months ended December 31, 2009:
| Operating Expenses |
Expenses ($ per Mcf) |
|||||||
| (In thousands, except per Mcf data) | ||||||||
| Barnett Shale |
$ | 18,638 | $ | 0.21 | ||||
| Mid-Continent |
13,236 | 0.24 | ||||||
| $ | 31,874 | $ | 0.22 | |||||
Depreciation and Amortization Expense. Depreciation and amortization expense for the three months ended December 31, 2009, was $20.7 million and primarily related to gathering systems.
General and Administrative Expense. During the three months ended December 31, 2009, general and administrative expenses were $2.9 million primarily attributable to costs allocated from Chesapeake related to centralized general and administrative services provided under our agreements with Chesapeake.
Interest Expense. Interest expense for the three months ended December 31, 2009 was $0.6 million, which was net of $1.8 million of capitalized interest. The interest expense was related to borrowings under our revolving credit facility.
Income Tax Expense (Benefit). Income tax expense for the three months ended December 31, 2009 was $0.6 million and was attributable to franchise taxes in the state of Texas. The Partnership and its subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the financial statements, other than Texas Franchise Tax.
Predecessor—Nine Months Ended September 30, 2009
Revenues. Predecessor’s revenues were $358.9 million with total volumetric throughput of 575 Bcf. The table below reflects our Predecessor’s revenues and throughput by region for the Predecessor 2009 Period:
| Revenues | Throughput (Bcf) |
|||||||
| (In thousands, except operational data) | ||||||||
| Barnett Shale |
$ | 201,217 | 248.1 | |||||
| Mid-Continent |
76,388 | 177.6 | ||||||
| Fayetteville Shale |
52,314 | 78.8 | ||||||
| Haynesville Shale |
24,106 | 60.7 | ||||||
| Appalachian Basin |
4,896 | 10.2 | ||||||
| $ | 358,921 | 575.4 | ||||||
Operating Expenses. Operating expenses were $146.6 million for the Predecessor 2009 Period. The table below reflects our Predecessor’s total operating expenses and operating expenses per Mcf of throughput by region for the Predecessor 2009 Period:
| Operating Expenses |
Expenses ($ per Mcf) |
|||||||
| (In thousands, except per Mcf data) | ||||||||
| Barnett Shale |
$ | 73,505 | $ | 0.30 | ||||
| Mid-Continent |
36,987 | 0.21 | ||||||
| Fayetteville Shale |
27,509 | 0.35 | ||||||
| Haynesville Shale |
5,784 | 0.10 | ||||||
| Appalachian Basin |
2,819 | 0.28 | ||||||
| $ | 146,604 | $ | 0.25 | |||||
Depreciation and Amortization Expense. Depreciation and amortization expense was $65.5 million for the Predecessor 2009 Period and was primarily related to gathering systems.
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General and Administrative Expense. General and administrative expense was $22.8 million for the Predecessor 2009 Period. During this period, our Predecessor incurred approximately $3.3 million of charges associated with the completion of the joint venture with GIP.
Impairment of Property, Plant and Equipment and Other Assets. Impairment of property, plant and equipment and other assets for the Predecessor 2009 Period was $90.2 million. Our Predecessor recorded an $86.2 million impairment associated with certain gathering systems located in the Mid-Continent region that were not expected to have future cash flows in excess of the book value of these systems. These systems were subsequently contributed to Chesapeake MLP Operating, L.L.C (formerly known as Chesapeake Midstream Partners, L.L.C.). Additionally, $4 million of debt issuance costs were expensed as a result of the amendment of our Predecessor’s $460 million credit facility.
(Gain) Loss on Sale of Assets. Our Predecessor recorded a $44.6 million loss on the sale of certain non-core and non-strategic gathering systems during the Predecessor 2009 Period.
Interest Expense. Interest expense for the Predecessor 2009 Period was $0.4 million, which is net of $6.5 million of capitalized interest. The interest expense was related to borrowings under our Predecessor’s revolving credit facility that was established in October of 2008.
Income Tax Expense (Benefit). Our Predecessor recorded income tax expense of $6.3 million for the Predecessor 2009 Period. This income tax expense was related to our Predecessor’s remaining taxable entity that was not contributed to us and was based on the 37.5 percent effective corporate tax rate of our Predecessor.
Predecessor—Year Ended December 31, 2008 vs. Year Ended December 31, 2007
Revenues. Total revenues increased $140.9 million, or 73 percent, to $332.8 million in 2008 from $191.9 million in 2007. Total volumetric throughput increased approximately 206 Bcf, or 55 percent, to 578 Bcf for 2008 from 372 Bcf for 2007. The increase was primarily due to additional throughput volumes resulting from the expansion of gathering systems primarily in the Barnett Shale region.
The table below reflects our Predecessor’s revenues and throughput by region for the years ended December 31, 2007 and 2008:
| Year Ended December 31, 2007 | Year Ended December 31, 2008 | |||||||||||||||
| Revenues | Throughput (Bcf) |
Revenues | Throughput (Bcf) |
|||||||||||||
| (In thousands, except operating data) | ||||||||||||||||
| Barnett Shale |
$ | 102,085 | 117.8 | $ | 198,424 | 257.9 | ||||||||||
| Mid-Continent |
73,491 | 214.0 | 84,080 | 225.7 | ||||||||||||
| Fayetteville Shale |
9,031 | 10.2 | 38,586 | 58.9 | ||||||||||||
| Haynesville Shale |
7,324 | 29.7 | 11,641 | 35.9 | ||||||||||||
| Appalachian Basin |
— | — | 52 | 0.1 | ||||||||||||
| $ | 191,931 | 371.7 | $ | 332,783 | 578.5 | |||||||||||
Operating Expenses. Operating expenses increased $64.2 million, or 83 percent, to $141.8 million in 2008 from $77.6 million in 2007. Operating expenses increased $0.04 per Mcf, or 19 percent, to $0.25 per Mcf for 2008 from $0.21 per Mcf for 2007. This increase was the result of the expansion of our Predecessor’s operations primarily in the Barnett Shale region. The increase was driven by more costs for 2008 compared to 2007 for labor, supplies and equipment incurred in the expansion of certain of our Predecessor’s gathering systems as well as increased costs for these services. The table below reflects our Predecessor’s total operating expenses and operating expenses per Mcf of throughput by region for the years ended December 31, 2007 and 2008:
| Year Ended December 31, 2007 | Year Ended December 31, 2008 | |||||||||||||||
| Operating Expenses |
Expenses ($ per Mcf) |
Operating Expenses |
Expenses ($ per Mcf) |
|||||||||||||
| (In thousands, except operating data) | ||||||||||||||||
| Barnett Shale |
$ | 42,952 | $ | 0.36 | $ | 80,919 | $ | 0.31 | ||||||||
| Mid-Continent |
27,473 | 0.13 | 37,211 | 0.16 | ||||||||||||
| Fayetteville Shale |
5,002 | 0.49 | 20,035 | 0.34 | ||||||||||||
| Haynesville Shale |
2,162 | 0.07 | 3,606 | 0.10 | ||||||||||||
| Appalachian Basin |
— | — | 32 | 0.24 | ||||||||||||
| $ | 77,589 | $ | 0.21 | $ | 141,803 | $ | 0.25 | |||||||||
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Depreciation and Amortization Expense. Depreciation and amortization expense increased $23.1 million, or 94 percent, to $47.6 million in 2008 from $24.5 million in 2007, primarily as a result of the addition of new gathering systems and the realization of a full year’s depreciation on property, plant and equipment and other assets added throughout the course of 2007.
General and Administrative Expense. General and administrative expense increased $6.5 million or 94 percent, to $13.4 million in 2008 from $6.9 million in 2007. This increase was primarily the result of the expansion of our Predecessor’s operations and the resulting increase in personnel and related expenses to support that growth.
Impairment of Property, Plant and Equipment and Other Assets. Our Predecessor recognized a charge of $30 million associated with the impairment of a treating facility. The impairment was the result of the facility’s location in an area of declining production and a reduction in the future expected throughput volumes by Chesapeake, based on its revised future development plans on the associated oil and natural gas properties that serve as the primary source of throughput volume for the facility. The treating facility was subsequently contributed to us upon its formation.
(Gain) Loss on Sale of Assets. Our Predecessor recorded a gain of $5.5 million in 2008 on the sale of certain gathering systems sold in conjunction with an upstream transaction executed by Chesapeake. No gain or loss was recorded in 2007.
Interest Expense. Interest expense for 2008 was $1.9 million compared to zero for 2007. Interest expense recorded for 2008 was related to borrowings under our Predecessor’s revolving credit facility that was established in October 2008.
Income Tax Expense (Benefit). Our Predecessor recorded an income tax benefit of $61.3 million in 2008 compared to income tax expense of $31.1 million in 2007. Historically, our Predecessor filed consolidated federal and state income tax returns as required with Chesapeake. Our Predecessor’s 2007 income tax expense was based on a 37.5 percent effective corporate income tax rate of our Predecessor. 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, did not result in a provision for income taxes in the financial statements. As such, our Predecessor provided for the change in legal structure by recording a $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. Accordingly, our Predecessor’s effective income tax rate for the year ended December 31, 2008 was (58.9) percent.
Liquidity and Capital Resources
Our ability to finance operations and fund capital expenditures will largely depend on our ability to generate sufficient cash flow to cover these expenses as well as the availability of borrowings under our revolving credit facility and our access to the capital markets. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. See Risk Factors in Item 1A of this annual report.
Historically, our sources of liquidity included cash generated from operations and borrowings under our revolving credit facility.
Working Capital. Working capital, defined as the amount by which current assets exceed current liabilities, is an indication of liquidity and the potential need for short-term funding. As of December 31, 2010 and 2009, we had working capital of $33.5 million and $49.4 million, respectively. Working capital decreased from December 31, 2009 to December 31, 2010 primarily as a result of the Springridge acquisition as we used $266 million of cash on hand to purchase long-lived assets.
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Cash Flows. Net cash provided by (used in) operating activities, investing activities and financing activities of the Partnership for the year ended December 31, 2010, were as follows:
| Year Ended December 31, 2010 |
||||
| ($ in thousands) | ||||
| Cash Flow Data: |
||||
| Net cash provided by (used in): |
||||
| Operating activities |
$ | 317,091 | ||
| Investing activities |
$ | (711,480 | ) | |
| Financing activities |
$ | 412,202 | ||
Operating Activities. Net cash provided by operating activities was $317.1 million for the year ended December 31, 2010. This amount was attributable to both cash flow from operations and changes in working capital. Cash flow from operations has increased as additional volumes have been brought onto our systems. Working capital is positive as a result of settlement of December 31, 2009 accounts receivable and accrued liabilities with Chesapeake in connection with the post-closing requirements of the purchase agreement relating to the joint venture transaction between Chesapeake and GIP.
Investing Activities. Net cash used in investing activities for the year ended December 31, 2010, was primarily attributable to the Springridge acquisition and capital spending related to the expansion of gathering systems.
Financing Activities. Net cash provided by financing activities was $412.2 million for the year ended December 31, 2010. This was primarily attributable to net proceeds of $474.6 million from the IPO and net proceeds from long-term borrowings of $205.0 million offset by distributions during the period of $262.4 million.
Sources of Liquidity. At December 31, 2010, our sources of liquidity included:
| • | cash on hand; |
| • | cash generated from operations; |
| • | borrowings under our revolving credit facility. |
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. Our revolving bank credit facility matures in July 2015, and provides up to $750.0 million of borrowing capacity, including a sub-limit of $25.0 million for same-day swing line advances and a sub-limit of $50.0 million for letters of credit. In addition, the credit facility contains an accordion feature that allows us to increase the available borrowing capacity under the facility up to $1.0 billion, subject to the satisfaction of certain closing conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the credit facility. Borrowings under the credit facility are secured by all of the assets of the Partnership and its subsidiaries, and loans thereunder (other than swing line loans) bear interest at our option at either (i) the greater of the reference rate of Wells Fargo Bank, NA, the federal funds effective rate plus 0.50 percent, and the one-month London Interbank Offered Rate (“LIBOR”) plus 1.00 percent, all of which is subject to a margin that varies from 1.75 percent to 2.25 percent per annum according to the most recent consolidated leverage ratio (as defined) or (ii) the Eurodollar rate, which is based on the LIBOR plus a margin that varies from 2.75 percent to 3.25 percent per annum according to the most recent consolidated leverage ratio. The unused portion of the credit facility is subject to a commitment fee of 0.50 percent per annum according to the most recent consolidated leverage ratio. At December 31, 2010, there were $249.1 million of outstanding borrowings under such credit facility leaving available borrowing capacity of $500.9 million.
Our revolving bank credit facility agreement requires maintenance of an indebtedness to EBITDA ratio (as defined in the revolving bank credit facility agreement) of not more than 4.50 to 1, and an EBITDA to interest expense ratio (as defined in the revolving bank credit facility agreement) of not less than 3.00 to 1. We were in compliance with all covenants under the agreement at December 31, 2010.
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Additionally, the credit facility contains various covenants and restrictive provisions which, among other things, limits the ability of the Partnership and its subsidiaries to incur additional indebtedness, make investments or loans, create liens and pay dividends or distributions. 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 credit facility could be declared immediately due and payable. The credit facility agreement also has cross default provisions that apply to any other indebtedness the Partnership has with an outstanding principal amount in excess of $15.0 million.
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 year ended December 31, 2010, expansion capital expenditures totaled $146.3 million and maintenance capital expenditures totaled $70.0 million. Our 2010 spending was primarily concentrated in our Barnett Shale region and in the Colony Granite Wash and Texas Panhandle Granite Wash plays in our Mid-Continent region. Our future capital expenditures may vary significantly from budgeted amounts and from period to period based on the investment opportunities that become available to us.
We continually review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Because our partnership agreement requires us to distribute most of the cash generated from operations to our unitholders and our general partner, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations that is not distributed to our unitholders and general partner, borrowings under our revolving credit facility and future issuances of equity and debt securities.
The Partnership is projecting expansion capital expenditures of $256 million and maintenance capital expenditures of $74 million for the twelve months ended December 31, 2011.
Distributions. We intend to pay a minimum quarterly distribution of $0.3375 per unit per quarter, which we expect to equate to approximately $47.6 million per quarter, or approximately $190.3 million per year, based on the number of common, subordinated and general partner units outstanding immediately after completion of the IPO. We do not have a legal obligation to pay this distribution.
On October 26, 2010, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.2165 per unit together with the corresponding distribution to the general partner. This amount represents a minimum quarterly distribution prorated for the 59-day period beginning on August 3, 2010 and ending on September 30, 2010. The cash distribution was paid on November 12, 2010 to unitholders of record on November 5, 2010 and to the general partner.
On January 31, 2011, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.3375 per unit for the fourth quarter 2010, or $1.35 per common unit on an annualized basis, together with the corresponding distribution to the general partner. The cash distribution was paid on February 14, 2011, to unitholders of record on February 10, 2011, and to the general partner.
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Contractual Obligations. At December 31, 2010, our contractual obligations included:
| Payments Due By Period | ||||||||||||||||||||
| Total | Less than 1 year |
1-3 years | 3-5 years | More than 5 years |
||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| Long-term debt (including interest)(1) |
$ | 311,318 | $ | 12,444 | $ | 24,887 | $ | 273,987 | $ | — | ||||||||||
| Operating leases |
113,114 | 57,007 | 50,374 | 5,733 | — | |||||||||||||||
| Total |
$ | 424,432 | $ | 69,451 | $ | 75,261 | $ | 279,720 | $ | — | ||||||||||
| (1) | Assumes constant interest rate of 3.99 percent on the outstanding balance of our revolving credit facility and a commitment fee of 0.50 percent on the unused portion of the facility. |
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 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.
Depreciation and amortization
Depreciation associated with our property, plant and equipment and other assets is calculated using the straight-line method, based on the estimated useful lives of our assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, we and our Predecessor make estimates with respect to useful lives and salvage values that we believe and our Predecessor believes, respectively, are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation. The estimated service lives of our functional asset groups are as follows:
| Asset Group |
Estimated Useful Lives (In years) | |
| Gathering systems |
20 | |
| Other fixed assets |
2 to 39 |
Intangible assets are generally amortized on a straight-line basis over their estimated useful lives, unless the assets economic benefits are consumed on an other than straight-line basis. The estimated useful life is the period over which the assets are expected to contribute directly or indirectly to the Partnership’s future cash flows.
Impairment of long-lived assets
Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount that the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risks associated with achieving the underlying cash flows.
Recently Issued Accounting Standards
The Financial Accounting Standards Board (“FASB”) recently issued the following standards which we reviewed to determine the potential impact on our financial statements upon adoption.
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In February 2010, the FASB amended its guidance on subsequent events to remove the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. The guidance was effective upon issuance. We adopted this guidance in 2010.
The FASB also issued new guidance requiring additional disclosures about fair value measurements, adding a new requirement to disclose transfers in and out of Levels 1 and 2 measurements and gross presentation of activity within a Level 3 roll forward. The guidance also clarified existing disclosure requirements regarding the level of disaggregation of fair value measurements and disclosures regarding inputs and valuation techniques. We determined that this guidance had no impact on our financial position or results of operations upon adoption. Required disclosures for the reconciliation of purchases, sales, issuance and settlements of financial instruments valued with a Level 3 method are effective beginning on January 1, 2011, and we do not expect the implementation to have a material impact on our financial position or results of operations. See Note 2 for discussion regarding fair value measurements.
In December 2010, the FASB issued guidance on disclosure of supplementary pro forma information for business combinations. The guidance specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The guidance also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, non-recurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenues and earnings. These amendments are effective prospectively for business combinations with an acquisition date on or after December 15, 2010, however, early adoption is permitted.
Forward-Looking Statements
Certain statements and information in this Annual Report on Form 10-K may constitute forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
| • | dependence on Chesapeake and Total for a substantial majority of our revenues; |
| • | the impact on our growth strategy and ability to increase cash distributions if Chesapeake and Total do not increase the volume of natural gas they provide to our gathering systems; |
| • | oil and natural gas realized prices; |
| • | the termination of our gas gathering agreements with Chesapeake or Total; |
| • | our potential inability to maintain existing distribution amounts or pay the minimum quarterly distribution to our unitholders; |
| • | the limitations that Chesapeake’s and our own level of indebtedness may have on our financial flexibility; |
| • | our ability to obtain new sources of natural gas, which is dependent on factors largely beyond our control; |
| • | the availability of capital resources to fund capital expenditures and other contractual obligations, and our ability to access those resources through the debt or equity capital markets; |
| • | competitive conditions; |
| • | the unavailability of third-party pipelines interconnected to our gathering systems or the potential that the volumes we gather do not meet the quality requirement of such pipelines; |
| • | new asset construction may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks; |
| • | our exposure to direct commodity price risk may increase in the future; |
| • | our ability to maintain and/or obtain rights to operate our assets on land owned by third parties; |
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| • | hazards and operational risks that may not be fully covered by insurance; |
| • | our dependence on Chesapeake for substantially all of our compression capacity; |
| • | our lack of industry and geographic diversification; and |
| • | legislative or regulatory changes, including changes in environmental regulations, environmental risks, regulations by FERC 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 in (i) Part 1, Item 1A “Risk Factors” and elsewhere in this report, (ii) our reports and registration statements filed from time to time with the SEC and (iii) other announcements we make from time to time.
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. | Quantitative and Qualitative Disclosures About Market Risk |
We are dependent on Chesapeake and Total for substantially all of our supply of natural gas volumes and are consequently subject to the risk of nonpayment or late payment by Chesapeake and Total 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, neither of our Total counterparties under our gas gathering agreement, nor the Total guarantor of those counterparties, is 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, 2010, a 125 basis point increase in the interest rate would have resulted in a nominal change 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 with Chesapeake and Total that are intended to support the stability of our cash flows. Natural gas prices are historically impacted by changes in the supply and demand of natural gas, as well as market uncertainty. However, an actual or anticipated prolonged reduction in natural gas prices or disparity in oil and natural gas pricing could result in reduced drilling in our areas of operations and, accordingly, in volumes of natural gas gathered by our systems. Notwithstanding the minimum volume commitments of Chesapeake and Total in our Barnett Shale region and the fee redetermination provisions under our gas gathering agreements, a reduction in volumes of natural gas gathered by our systems could adversely affect both our profitability and our cash flows. Adverse effects on our cash flows from reductions in natural gas prices could adversely affect our ability to make cash distributions to our unitholders.
We have agreed with Chesapeake on MMBtu based caps on fuel, lost and unaccounted for gas on certain of our systems with respect Chesapeake’s volumes in our Barnett Shale and Mid-Continent regions. In the event that we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel, lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.
Additionally, an increase in commodity prices could result in increased costs of steel and other products that we use in the operation of our business, as well as the cost of obtaining rights-of-way for property on which our assets are located. Accordingly, our operating expenses and capital expenditures could increase as a result of an increase in commodity prices.
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| ITEM 8. | Financial Statements and Supplementary Data |
CHESAPEAKE MIDSTREAM PARTNERS, L.P.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Chesapeake Midstream GP, L.L.C, as General Partner of Chesapeake Midstream Partners, L.P. and to the Unitholders:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in equity and of cash flows present fairly, in all material respects, the financial position of Chesapeake Midstream Partners, L.P. and its subsidiaries (the “Partnership”) at December 31, 2010 and 2009, and the results of their operations and their cash flows for the year ended December 31, 2010 and for the period from October 1, 2009 to December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in the accompanying consolidated financial statements and footnotes, Chesapeake Midstream Partners, L.P. earned substantially all of its revenues and has other significant transactions with affiliated entities.
/s/ PricewaterhouseCoopers LLP
Tulsa, OK
March 11, 2011
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the partners of Chesapeake Midstream Development, L.P.:
In our opinion, the accompanying consolidated statements of operations, of changes in equity and of cash flows present fairly, in all material respects, the results of Chesapeake Midstream Development, L.P.’s (the “Predecessor”) operations and their cash flows for the period from January 1, 2009 to September 30, 2009 and the year ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Predecessor’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in the accompanying consolidated financial statements and footnotes, Chesapeake Midstream Development L.P. earned substantially all of its revenues and has other significant transactions with affiliated entities.
/s/ PricewaterhouseCoopers LLP
Tulsa, OK
April 6, 2010
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
| December 31, 2010 |
December 31, 2009 |
|||||||
| ($ in thousands) | ||||||||
| ASSETS | ||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 17,816 | $ | 3 | ||||
| Accounts receivable, including $88,009 and $165,065 from related parties at December 31, 2010 and 2009, respectively |
107,095 | 165,771 | ||||||
| Other current assets |
6,576 | 1,743 | ||||||
| Total current assets |
131,487 | 167,517 | ||||||
| Property, plant and equipment: |
||||||||
| Gathering systems |
2,544,053 | 2,013,347 | ||||||
| Other fixed assets |
41,125 | 34,130 | ||||||
| Less: Accumulated depreciation |
(358,269 | ) | (271,062 | ) | ||||
| Total property, plant and equipment, net |
2,226,909 | 1,776,415 | ||||||
| Intangible contracts |
172,481 | – | ||||||
| Deferred loan costs, net |
15,039 | 14,743 | ||||||
| Total assets |
$ | 2,545,916 | $ | 1,958,675 | ||||
| LIABILITIES AND EQUITY | ||||||||
| Current liabilities: |
||||||||
| Accounts payable |
$ | 39,619 | $ | 22,940 | ||||
| Accrued liabilities, including $42,674 and $84,078 from related parties at December 31, 2010 and 2009, respectively |
58,372 | 95,158 | ||||||
| Total current liabilities |
97,991 | 118,098 | ||||||
| Long-term liabilities: |
||||||||
| Revolving bank credit facility |
249,100 | 44,100 | ||||||
| Other liabilities |
4,257 | 2,850 | ||||||
| Total long-term liabilities |
253,357 | 46,950 | ||||||
| Commitments and contingencies (Note 12) |
||||||||
| Equity: |
||||||||
| Common units (69,083,265 issued and outstanding at December 31, 2010) |
1,285,619 | — | ||||||
| Subordinated units (69,076,122 issued and outstanding at December 31, 2010) |
873,304 | — | ||||||
| General partner units (2,819,434 issued and outstanding at December 31, 2010) |
35,645 | — | ||||||
| Members’ equity |
— | 1,793,627 | ||||||
| Total equity |
2,194,568 | 1,793,627 | ||||||
| Total liabilities and equity |
$ | 2,545,916 | $ | 1,958,675 | ||||
The accompanying notes are an integral part of the consolidated financial statements.
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
| Year
Ended December 31, 2010 |
Three Months
Ended December 31, 2009 |
Predecessor | ||||||||||||||||||||||
| Nine Months Ended September 30, 2009 |
Year
Ended December 31, 2008 |
|||||||||||||||||||||||
| ($ in thousands, except per unit data) | ||||||||||||||||||||||||
| Revenues, including revenue from affiliates (Notes 5 and 7) |
$ | 459,153 | $ | 107,377 | $ | 358,921 | $ | 332,783 | ||||||||||||||||
| Operating Expenses |
||||||||||||||||||||||||
| Operating expenses, including expenses from affiliates (Note 5) |
133,293 | 31,874 | 146,604 | 141,803 | ||||||||||||||||||||
| Depreciation and amortization expense |
93,477 | 20,699 | 65,477 | 47,558 | ||||||||||||||||||||
| General and administrative expense, including expenses from affiliates (Note 5) |
31,992 | 2,854 | 22,782 | 13,362 | ||||||||||||||||||||
| Impairment of property, plant and equipment and other assets |
— | — | 90,207 | 30,000 | ||||||||||||||||||||
| (Gain) Loss on sale of assets |
285 | 34 | 44,566 | (5,541 | ) | |||||||||||||||||||
| Total operating expenses |
259,047 | 55,461 | 369,636 | 227,182 | ||||||||||||||||||||
| Operating income (loss) |
200,106 | 51,916 | (10,715 | ) | 105,601 | |||||||||||||||||||
| Other Income (Expense) |
||||||||||||||||||||||||
| Interest expense (Note 11) |
(2,550 | ) | (619 | ) | (347 | ) | (1,871 | ) | ||||||||||||||||
| Other income |
102 | 34 | 29 | 278 | ||||||||||||||||||||
| Income before income tax expense |
197,658 | 51,331 | (11,033 | ) | 104,008 | |||||||||||||||||||
| Income tax expense (benefit) |
2,431 | 639 | 6,341 | (61,287 | ) | |||||||||||||||||||
| Net income (loss) |
$ | 195,227 | $ | 50,692 | $ | (17,374 | ) | $ | 165,295 | |||||||||||||||
| Limited partner interest in net income |
||||||||||||||||||||||||
| Net income(1) |
$ | 109,396 | $ | n/a | n/a | n/a | ||||||||||||||||||
| Less general partner interest in net income |
(2,188 | ) | n/a | n/a | n/a | |||||||||||||||||||
| Limited partner interest in net income |
$ | 107,208 | $ | n/a | n/a | n/a | ||||||||||||||||||
| Net income per limited partner unit – basic and diluted |
||||||||||||||||||||||||
| Common units |
$ | 0.78 | $ | n/a | n/a | n/a | ||||||||||||||||||
| Subordinated units |
$ | 0.78 | $ | n/a | n/a | n/a | ||||||||||||||||||
| Weighted average limited partner units outstanding – basic and diluted (in thousands) |
||||||||||||||||||||||||
| Common units |
69,083 | n/a | n/a | n/a | ||||||||||||||||||||
| Subordinated units |
69,076 | n/a | n/a | n/a | ||||||||||||||||||||
| (1) | Reflective of general and limited partner interest in net income since closing the Partnership’s IPO on August 3, 2010. See Note 4 to the consolidated financial statements. |
The accompanying notes are an integral part of the consolidated financial statements.
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Predecessor | ||||||||||||||||||
| Year Ended December 31, 2010 |
Three Months Ended December 31, 2009 |
Nine Months Ended September 30, 2009 |
Year Ended December 31, 2008 |
|||||||||||||||
| ($ in thousands) | ||||||||||||||||||
| Cash flows from operating activities: |
||||||||||||||||||
| Net income (loss) |
$ | 195,227 | $ | 50,692 | $ | (17,374 | ) | $ | 165,295 | |||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||||||||
| Depreciation and amortization |
93,477 | 20,699 | 65,477 | 47,558 | ||||||||||||||
| Deferred income taxes |
— | — | 6,341 | (61,287 | ) | |||||||||||||
| Impairment of property, plant and equipment and other assets |
— | — | 90,207 | 30,000 | ||||||||||||||
| (Gain) loss on sale of assets |
285 | 34 | 44,566 | (5,541 | ) | |||||||||||||
| Other non-cash items |
100 | (39 | ) | (282 | ) | (537 | ) | |||||||||||
| Changes in assets and liabilities: |
||||||||||||||||||
| (Increase) decrease in accounts receivable |
58,172 | (70,792 | ) | (29,553 | ) | (107,863 | ) | |||||||||||
| Increase (decrease) in other assets |
(4,833 | ) | (136 | ) | (1,901 | ) | (138 | ) | ||||||||||
| Increase (decrease) in accounts payable |
7,474 | (23,630 | ) | (82,112 | ) | 163,372 | ||||||||||||
| Increase (decrease) in accrued liabilities |
(32,811 | ) | 37,902 | 25,379 | 5,915 | |||||||||||||
| Net cash provided by operating activities |
317,091 | 14,730 | 100,748 | 236,774 | ||||||||||||||
| Cash flows from investing activities: |
||||||||||||||||||
| Additions to property, plant and equipment |
(216,303 | ) | (46,377 | ) | (756,883 | ) | (1,402,449 | ) | ||||||||||
| Acquisition of gathering system assets |
(500,000 | ) | — | — | — | |||||||||||||
| Proceeds from sale of assets |
4,823 | 25 | 65,889 | 17,615 | ||||||||||||||
| Net cash used in investing activities |
(711,480 | ) | (46,352 | ) | (690,994 | ) | (1,384,834 | ) | ||||||||||
| Cash flows from financing activities: |
||||||||||||||||||
| Proceeds from long-term debt borrowings |
529,300 | 100,744 | 870,373 | 508,900 | ||||||||||||||
| Payments on long-term debt borrowings |
(324,300 | ) | (68,817 | ) | (1,318,200 | ) | (48,900 | ) | ||||||||||
| Proceeds from issuance of common units, net of offering costs |
474,579 | — | — | — | ||||||||||||||
| Distributions to unit holders |
(30,522 | ) | — | — | — | |||||||||||||
| Distributions to partners |
(231,919 | ) | — | (10,153 | ) | — | ||||||||||||
| Contribution from Predecessor |
177 | — | — | — | ||||||||||||||
| Contributions from Chesapeake |
— | — | 567,828 | 780,553 | ||||||||||||||
| Proceeds from sale of noncontrolling interest |
— | — | 587,500 | — | ||||||||||||||
| Joint venture transaction costs |
— | — | (16,130 | ) | — | |||||||||||||
| Debt issuance cost |
(5,113 | ) | (337 | ) | (16,950 | ) | (10,494 | ) | ||||||||||
| Net cash provided by financing activities |
412,202 | 31,590 | 664,268 | 1,230,059 | ||||||||||||||
| Net increase (decrease) in cash and cash equivalents |
17,813 | (32 | ) | 74,022 | 81,999 | |||||||||||||
| Cash and cash equivalents, beginning of period |
3 | 35 | 82,025 | 26 | ||||||||||||||
| Cash and cash equivalents, end of period |
$ | 17,816 | $ | 3 | 156,047 | 82,025 | ||||||||||||
| Supplemental disclosure of non-cash investing activities: |
||||||||||||||||||
| Changes in accounts payable and other liabilities related to purchases of property, plant and equipment |
$ | 12,633 | $ | (2,812 | ) | $ | (52,521 | ) | $ | 58,458 | ||||||||
| Changes in other liabilities related to asset retirement obligations |
$ | 28 | $ | 136 | $ | (2,893 | ) | $ | 1,560 | |||||||||
| Contributions of property, plant and equipment to Chesapeake |
$ | 11,705 | $ | 1,749 | $ | 91,462 | $ | — | ||||||||||
| Supplemental disclosure of cash payments for Interest |
$ | 3,607 | $ | 877 | $ | 7,478 | $ | 1,152 | ||||||||||
| Supplemental disclosure of cash payments for taxes |
$ | 645 | $ | — | $ | — | $ | — | ||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
| Partners’ Equity | ||||||||||||||||||||
| Limited Partners | ||||||||||||||||||||
| Members’ Equity |
Common | Subordinated | General Partner |
Total | ||||||||||||||||
| ($ in thousands) | ||||||||||||||||||||
| Predecessor: |
||||||||||||||||||||
| Balance at December 31, 2007 |
$ | 847,421 | $ | — | $ | — | $ | — | $ | 847,421 | ||||||||||
| Formation of partnership – allocation of division equity |
— | — | — | — | — | |||||||||||||||
| Contributions from Chesapeake |
780,553 | — | — | — | 780,553 | |||||||||||||||
| Net income |
165,295 | — | — | — | 165,295 | |||||||||||||||
| Balance at December 31, 2008 |
$ | 1,793,269 | $ | — | $ | — | $ | — | $ | 1,793,269 | ||||||||||
| Contributions from Chesapeake |
659,291 | — | — | — | 659,291 | |||||||||||||||
| Net loss |
(17,374 | ) | — | — | — | (17,374 | ) | |||||||||||||
| Sale of noncontrolling interest in midstream joint venture |
587,500 | — | — | — | 587,500 | |||||||||||||||
| Noncontrolling interest offering cost |
(16,130 | ) | — | — | — | (16,130 | ) | |||||||||||||
| Distribution to noncontrolling interest Owner |
(10,153 | ) | — | — | — | (10,153 | ) | |||||||||||||
| Allocation of joint venture capital to Global Infrastructure Partners |
— | — | — | — | — | |||||||||||||||
| Balance at September 30, 2009 |
$ | 2,996,403 | $ | — | $ | — | $ | — | $ | 2,996,403 | ||||||||||
| Successor: |
||||||||||||||||||||
| Members’ equity upon formation |
1,741,186 | — | — | — | 1,741,186 | |||||||||||||||
| Contributions from predecessor |
1,749 | — | — | — | 1,749 | |||||||||||||||
| Net income |
50,692 | — | — | — | 50,692 | |||||||||||||||
| Balance at December 31, 2009 |
$ | 1,793,627 | $ | — | $ | — | $ | — | $ | 1,793,627 | ||||||||||
| Distributions to Predecessor, net |
(6,574 | ) | — | — | — | (6,574 | ) | |||||||||||||
| Distributions to members |
(169,500 | ) | — | — | — | (169,500 | ) | |||||||||||||
| Net income attributable to the period from January 1, 2010 through August 2, 2010 |
85,831 | — | — | — | 85,831 | |||||||||||||||
| Contribution of net assets to Chesapeake Midstream Partners, L.P. |
(1,703,384 | ) | 834,658 | 834,658 | 34,068 | — | ||||||||||||||
| Issuance of common units to public, net of offering and other costs |
— | 474,579 | — | — | 474,579 | |||||||||||||||
| Distribution of proceeds to partner from exercise of over-allotment option |
— | (62,419 | ) | — | — | (62,419 | ) | |||||||||||||
| Non-cash equity based compensation |
— | 150 | — | — | 150 | |||||||||||||||
| Distributions to unitholders |
— | (14,956 | ) | (14,955 | ) | (611 | ) | (30,522 | ) | |||||||||||
| Net income attributable to the period from August 3, 2010 through December 31, 2010 |
— | 53,607 | 53,601 | 2,188 | 109,396 | |||||||||||||||
| Balance at December 31, 2010 |
$ | — | $ | 1,285,619 | $ | 873,304 | $ | 35,645 | $ | 2,194,568 | ||||||||||
The accompanying notes are an integral part of the consolidated financial statements.
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| 1. | Description of Business and Basis of Presentation |
Basis of presentation. Chesapeake Midstream Partners, L.P., (the “Partnership”) a Delaware limited partnership formed in January 2010, is principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. As of December 31, 2010, the Partnership’s assets consisted of 192 gathering systems, five natural gas treating facilities, and three gas processing facilities. The Partnership’s assets are located in Texas, Louisiana, Oklahoma, Kansas and Arkansas. The Partnership provides gathering, treating and compression services to Chesapeake Energy Corporation (“Chesapeake”) and Total Gas and Power North America, Inc. (“Total”), the Partnership’s primary customers, and other third-party producers under long-term, fixed-fee contracts.
Chesapeake Midstream Development, L.P. (“CMD” or our “Predecessor”) is a Delaware limited partnership formed on February 29, 2008 to own, operate and develop midstream energy assets. Upon formation, gathering and treating assets of Chesapeake Energy Marketing, Inc. (“CEMI”), a wholly owned subsidiary of Chesapeake, were contributed to CMD. CEMI is the sole limited partner of CMD with a 98 percent ownership interest, and Chesapeake Midstream Management L.L.C. (“CMM”) is the general partner of CMD with a 2 percent ownership interest. CMM is a wholly owned subsidiary of CEMI.
On September 30, 2009, our Predecessor formed a joint venture with Global Infrastructure Partners – A, L.P., and affiliated funds managed by Global Infrastructure Management, L.L.C., and certain of their respective subsidiaries and affiliates (“GIP”), to own and operate natural gas midstream assets. As part of the transaction, our Predecessor contributed certain natural gas gathering and treating assets to a new entity, Chesapeake Midstream Partners, L.L.C. and GIP purchased a 50 percent interest in the newly formed joint venture.
The assets contributed to the joint venture and ultimately the Partnership were substantially all of our Predecessor’s midstream assets in the Barnett Shale region and certain of its midstream assets in the Arkoma, Chesapeake, Delaware and Permian Basins. Subsidiaries of our Predecessor continued to operate midstream assets outside of the joint venture. At December 31, 2010 these included natural gas gathering assets primarily in the Fayetteville Shale (Chesapeake announced the proposed sale of its Fayetteville assets in February 2011), Haynesville Shale, Marcellus Shale (including other areas in the Appalachian Basin) and the Eagle Ford Shale.
For purposes of these financial statements, the “Partnership”, when used in a historical context, refers to the financial results of Chesapeake Midstream Partners, L.L.C. from its inception on September 30, 2009 through the closing date of our initial public offering (“IPO”) on August 3, 2010 and to Chesapeake Midstream Partners, L.P. and its subsidiaries thereafter. “Predecessor” refers to Chesapeake Midstream Development, L.P. prior to September 30, 2009. “Chesapeake” refers to Chesapeake Energy Corporation and “GIP” refers to Global Infrastructure Partners – A, L.P., and affiliated funds managed by Global Infrastructure Management, L.L.C., and certain of their respective subsidiaries and affiliates. “Total”, when discussing the upstream joint venture with Chesapeake, refers to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A., and when discussing 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 are presented for current and Predecessor periods, which relate to the accounting periods preceding and succeeding the September 30, 2009 joint venture transaction described in Note 1. The current and Predecessor periods have been separated by a vertical line on the face of the consolidated financial statements to highlight the fact that the financial information for such periods represents different entities.
The accompanying consolidated financial statements of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). To conform to these accounting principles, management makes estimates and assumptions that affect the amounts reported in the consolidated financial statements and the notes thereto. These estimates are evaluated on an ongoing basis, utilizing historical experience and other methods considered reasonable under the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates. Effects on the Partnership’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Offerings and acquisitions.
IPO. On August 3, 2010, the Partnership completed its IPO of 24,437,500 common units (such amount includes 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option on August 3, 2010) at a price of $21.00 per unit. The Partnership’s common units are listed on the New York Stock Exchange (the “NYSE”) under the symbol “CHKM”.
We received gross offering proceeds of approximately $513.2 million less approximately $38.6 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of the contribution agreement, we distributed the approximate $62.4 million of net proceeds from the exercise of the over-allotment option to GIP on August 3, 2010. We used the net offering proceeds of $412.2 million to repay approximately $110.0 million of borrowings under our revolving credit facility and to pay approximately $5.1 million of fees related to the amendment of our revolving credit facility. The remainder was used to fund expansion capital expenditures and part of the Springridge acquisition.
Upon completion of the IPO, Chesapeake and GIP conveyed to us a 100 percent membership interest in Chesapeake MLP Operating, L.L.C., which owned all of our assets since September 2009.
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 consists of 226 miles of gathering pipeline primarily located in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, we entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication, annual fee redetermination and a minimum volume commitment. These assets are referred to collectively as the “Springridge assets” and the acquisition is referred to as the “Springridge acquisition.”
Presentation of Partnership acquisitions. For purposes of this annual report, the assets in which the Partnership owned an interest as of December 31, 2010, which consist of the initial assets and the Springridge assets, are referred to collectively as the “Partnership Assets.” References to “periods prior to the Partnership’s acquisition of the Partnership Assets” and similar phrases refer to periods prior to September 30, 2009, with respect to the initial assets, and periods prior to December 21, 2010, with respect to the Springridge assets. Reference to “periods including and subsequent to the Partnership’s acquisition of the Partnership Assets” and similar phrases refer to periods including and subsequent to September 30, 2009, with respect to the initial assets, and periods including and subsequent to December 21, 2010, with respect to the Springridge assets.
The consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership Assets have been prepared from Chesapeake’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the assets and operated as a separate entity during the periods reported. In addition, certain amounts in prior periods have been reclassified to conform to the current presentation.
Limited partner and general partner units. The following table summarizes common, subordinated and general partner units issued during the year ended December 31, 2010:
| Limited Partner Units | ||||||||||||||||
| Common | Subordinated | General Partner Units |
Total | |||||||||||||
| Balance at December 31, 2009 |
— | — | — | — | ||||||||||||
| Initial public offering and contribution of initial assets |
69,076,122 | 69,076,122 | 2,819,434 | 140,971,678 | ||||||||||||
| Long-term incentive plan awards |
7,143 | — | — | 7,143 | ||||||||||||
| Balance at December 31, 2010 |
69,083,265 | 69,076,122 | 2,819,434 | 140,978,821 | ||||||||||||
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Holdings of partnership equity. As of December 31, 2010, Chesapeake held 1,409,717 general partner units representing a 1.0 percent general partner interest in the Partnership, 50 percent of the Partnership IDRs, 23,913,061 common units and 34,538,061 subordinated units. Chesapeake’s common and subordinated units represent an aggregate 41.5 percent limited partner interest in the Partnership. GIP held 1,409,717 general partner units representing a 1.0 percent general partner interest in the Partnership, 50 percent of the Partnership IDRs, 20,725,561 common units and 34,538,061 subordinated units. GIP’s common and subordinated units represent an aggregate 39.2 percent limited partner interest in the Partnership. The public held 24,444,643 common units, representing a 17.3 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 its estimates.
Cash and cash equivalents. For purposes of the consolidated financial statements, investments in all highly liquid instruments with original maturities of three months or less at date of purchase are considered to be cash equivalents. The Partnership had approximately $17.8 million and $3.0 million of cash and cash equivalents as of December 31, 2010 and 2009, 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, 2010 and 2009, book overdrafts of $4.0 million 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, 2010 and 2009, no allowance for doubtful accounts was necessary.
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. Our Predecessor recorded a $44.6 million loss on the sale of certain non-core, non-strategic gathering systems during the period ended September 30, 2009 as well as a $5.5 million gain on the sale of certain gathering systems sold in conjunction with an upstream transaction effected by Chesapeake during the year ended December 31, 2008.
Certain of the gathering systems of the Partnership are subject to an agreement with a subsidiary of Chesapeake, which provides the Partnership rights and obligations equivalent to a capital lease. Under the terms of the agreement, the Partnership has rights to the associated capital assets for as long as the assets are in operation. Specifically, the Partnership will pay all costs associated with the related gathering systems, including all capital costs, operating costs and direct and indirect overhead costs. In exchange for paying such costs and for the services it provides pursuant to this agreement, the Partnership receives revenues derived from operation of the gathering systems. At December 31, 2010 and 2009, approximately $122.5 million and $120.9 million ($109.2 million and $113.7 million net of accumulated depreciation) of the Partnership’s gathering system assets were held under such agreement, respectively. Payments for capital costs under the agreement are made as the associated capital assets are constructed and, accordingly, the Partnership has no capital lease obligation liability associated with the assets held under this agreement as of December 31, 2010.
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.
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Impairment of long-lived assets. Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount that the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risks associated with achieving the underlying cash flows.
During 2009, our Predecessor recognized an impairment charge of $86.2 million associated with certain mid-continent gathering systems. The impairment was the result of a reduction in the future expected throughput volumes on these systems by Chesapeake based on its revised future development plans of the underlying oil and gas properties, as well as the impact of the terms of the new gas gathering agreements entered into with Chesapeake in conjunction with the formation of the joint venture on September 30, 2009. These systems were subsequently contributed to the Partnership upon its formation. Additionally, our Predecessor also expensed $4 million of debt issuance costs as a result of the amendment of the credit facility (See Note 11) resulting in total impairments of $90.2 million in 2009.
During 2008, CMD recognized a charge of $30 million associated with the impairment of a treating facility. The impairment was the result of the facility’s location in an area of declining production and a reduction in the future expected throughput volumes by Chesapeake, based on their revised future development plans on the associated oil and gas properties that serve as the primary source of throughput volume for the facility. The treating facility was subsequently contributed to the Partnership upon its formation.
Asset retirement obligations. Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at its 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 its expected settlement value. Subsequent to the initial recognition, the liability is adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to property, plant and equipment) and for accretion of the liability due to the passage of time, until the obligation is settled. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the associated asset carrying amount. Revisions in estimated asset retirement obligations may result from changes in estimated inflation rates, discount rates, retirement costs and the estimated timing of settling asset retirement obligations.
Fair value. The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:
Level 1 — inputs represent quoted prices in active markets for identical assets or liabilities.
Level 2 — inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).
Level 3 — inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement).
Nonfinancial assets and liabilities initially measured at fair value include third-party business combinations, impaired long-lived assets (asset groups), and initial recognition of asset retirement obligations.
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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. Our Predecessor’s revenues were derived almost exclusively from related parties and were charged under short-term contracts at market sensitive rates. The Partnership currently derives substantially all of its revenues through gas gathering agreements with Chesapeake and Total. Pursuant to the applicable gas gathering agreements, Chesapeake and Total have agreed to minimum volume commitments covering production in the Barnett Shale region for each year through December 31, 2018 and for the six month period ending June 30, 2019, and in the Haynesville Shale region for each year through December 31, 2013. In the event either Chesapeake or Total does not meet its minimum volume commitment to the Partnership in the Barnett Shale region or Chesapeake does not meet its minimum volume commitment to the Partnership in the Haynesville Shale region, for any annual period (or six month period with respect to the six months ending June 30, 2019 in the Barnett Shale region) during the minimum volume commitment period, Chesapeake and Total will be obligated to pay a fee equal to the applicable fee for each Mcf by which the applicable party’s minimum volume commitment for such year (or six month period with respect to the six months ending June 30, 2019) exceeds the actual volumes gathered from such party’s production. The revenue associated with such shortfall fees is recognized in the fourth quarter of each year.
Revenues consist of fees recognized for the gathering, treating and compression of natural gas to major interstate and intrastate pipelines. Revenues are recognized when the service is performed and is based upon non-regulated rates and the related gathering, treating and compression volumes.
Deferred Loan Costs. External costs incurred in connection with closing the revolving bank credit facilities are capitalized as deferred loan costs and amortized over the life of the related agreement. Amortization is included in depreciation and amortization 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, 2010 and 2009.
Equity Based Compensation. Certain employees of Chesapeake have been seconded to the Partnership to provide operating, routine maintenance and other services with respect to the business under the direction, supervision and control of the Partnership’s general partner. A number of these employees receive equity-based compensation through Chesapeake’s stock-based compensation programs, which consist of restricted stock issued to employees.
The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. However, the Partnership’s expense is allocated based on the lesser of the value at grant date or vest date. This value is amortized over the vesting period, which is generally four or five years from the date of grant. To the extent compensation cost relates to employee activities directly involved in gathering or treating operations, such amounts are charged to the Partnership and our Predecessor and are reflected as operating expenses. Included in operating expenses is stock-based compensation of $2.1 million and $0.6 million for the Partnership during the periods ended December 31, 2010 and 2009, respectively, and $5.3 million and $3.6 million for our Predecessor during the periods ended September 30, 2009 and December 31, 2008, respectively. To the extent compensation cost relates to employees indirectly involved in gathering or treating operations, such amounts are charged to the Partnership and our Predecessor through an overhead allocation and are reflected as general and administrative expenses.
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Upon completion of the IPO, awards of Partnership units with a value of approximately $50,000 per award were made to each of the three independent directors of the Partnership’s general partner pursuant to the Chesapeake Midstream Long-Term Incentive Plan, or “LTIP,” in connection with their initial appointment to the Board of Directors of the Partnership’s general partner. The 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.
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 contract acquired with the Springridge gathering system is 15 years.
The Partnership assesses long-lived assets, including property, plant and equipment and intangible assets, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed by comparing the carrying amount of an asset to undiscounted future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured as the amount by which the carrying amounts exceed the fair value of the assets.
Business Combinations. We make 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. We then determine 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 relations, trade names, and licenses and permits. We value customer contracts using a discounted cash flow model. We value customer relations as the fair value of avoided customer churn costs compared to industry norms.
Income taxes. Chesapeake and its subsidiaries historically have filed a consolidated federal income tax return and other state returns as required. Our Predecessor and certain of its subsidiaries, as a partnership or limited liability companies, were not subject to federal income taxes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to the partners of our Predecessor and, accordingly, do not result in a provision for income taxes in the accompanying financial statements. As a master limited partnership, we are a pass-through entity and also not subject to federal income taxes and most state income taxes with the exception of Texas Franchise Tax. For federal and state income tax purposes, all income, expenses, gains, losses and tax credits generate flow through to the owners, and accordingly, do not result in a provision for income taxes.
Income taxes have been provided by our Predecessor for its subsidiaries which are subject to federal and state income tax on the basis of their separate company income and deductions. Income taxes have also been provided for the operations of the midstream business prior to its contribution to our Predecessor on February 28, 2008, during which period the operations were owned by CEMI and were subject to income taxes. Deferred income taxes have been provided for temporary differences between the book and tax carrying amounts of assets and liabilities held by taxable entities of our Predecessor. These differences create taxable or tax deductible amounts for future periods. Current taxes payable of the Partnership related to Texas franchise tax will be paid by the Partnership. Current taxes payable of our Predecessor were paid by Chesapeake and have been reflected as contributions from Chesapeake in the accompanying statements of partners’ capital/division equity. Chesapeake reimbursed our Predecessor for its net operating losses utilized in the completion of Chesapeake’s consolidated federal tax returns.
There were no uncertain tax positions at December 31, 2009 and 2008.
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
| 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, 2009, the Partnership distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. During year ended December 31, 2010, the Partnership paid cash distributions to its unitholders of approximately $30.5 million, representing the $0.2165 per-unit distribution for the quarter ended September 30, 2009. See also Note 14 — Subsequent Events concerning distributions approved in January 2011 for the quarter ended December 31, 2010.
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 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, 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 $0.3375 per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2013. Also, if the Partnership has earned and paid at least 150 percent of the minimum quarterly distribution on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of removal. When the subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages. All subordinated units are held indirectly by Chesapeake and GIP.
General Partner Interest and Incentive Distribution Rights. Initially, our general partner will be 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 current general partner interest. Our general partner’s initial two percent interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us to maintain its two percent general partner interest. After distributing amounts equal to the minimum quarterly distribution to common and subordinated unitholders and distributing amounts to eliminate any arrearages to common unitholders, the Partnership’s general partner is entitled to incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds specified target levels shown below:
| Total quarterly distribution per unit | Unitholders | General partner | ||||||||||
| Minimum Quarterly Distribution |
$0.3375 | 98.0 | % | 2.0 | % | |||||||
| First Target Distribution |
up to $0.388125 | 98.0 | % | 2.0 | % | |||||||
| Second Target Distribution |
above $0.388125 up to $0.421875 | 85.0 | % | 15.0 | % | |||||||
| Third Target Distribution |
above $0.421875 up to $0.50625 | 75.0 | % | 25.0 | % | |||||||
| Thereafter |
above $0.50625 | 50.0 | % | 50.0 | % | |||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The table above assumes that the Partnership’s general partner maintains its 2 percent general partner interest, that there are no arrearages on common units and the general partner continues to own the IDRs. The maximum distribution sharing percentage of 50.0 percent includes distributions paid to the general partner on its two percent general partner interest and does not include any distributions that the general partner may receive on limited partner units that it owns or may acquire.
| 4. | Net Income per Limited Partner Unit |
The Partnership’s net income attributable to the Partnership Assets for periods including and subsequent to the Partnership’s acquisitions of the Partnership Assets is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to unvested units granted under the LTIP and incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to available cash (as defined by the partnership agreement) for the period. The Partnership’s net income allocable to the limited partners is allocated between the common and subordinated unitholders by applying the provisions of the partnership agreement that govern actual cash distributions as if all earnings for the period had been distributed. Accordingly, if current net income allocable to the limited partners is less than the minimum quarterly distribution, or if cumulative net income allocable to the limited partners since August 3, 2010 is less than the cumulative minimum quarterly distributions, more income is allocated to the common unitholders than the subordinated unitholders for that quarterly period.
Basic and diluted net income per limited partner unit is calculated by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period. The common units issued during the period are included on a weighted-average basis for the days in which they were outstanding.
The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated limited partner units (in thousands, except per-unit information):
| Year Ended December 31, 2010 |
||||
| Net income. |
$ | 195,227 | ||
| Less Successor interest in net income (1) |
85,831 | |||
| Less general partner interest in net income |
2,188 | |||
| Limited partner interest in net income |
$ | 107,208 | ||
| Net income allocable to common units |
$ | 53,607 | ||
| Net income allocable to subordinated units |
53,601 | |||
| Limited partner interest in net income |
$ | 107,208 | ||
| Net income per limited partner unit – basic and diluted |
||||
| Common units |
$ | 0.78 | ||
| Subordinated units |
0.78 | |||
| Total |
$ | 0.78 | ||
| Weighted average limited partner units outstanding – basic and diluted |
||||
| Common units |
69,083,265 | |||
| Subordinated units |
69,076,122 | |||
| Total |
138,159,387 | |||
| (1) | Includes net income attributable to the initial assets up to August 3, 2010 and net income attributable to the Springridge assets up to December 20, 2010. |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
| 5. | Transactions with Affiliates |
Affiliate transactions. In the normal course of business, natural gas gathering and treating services are provided to Chesapeake and its affiliates. Revenues are derived almost exclusively from Chesapeake, which includes volumes attributable to third-party interest owners that participate in Chesapeake’s operated wells.
Contribution of Partnership Assets to the Partnership. Upon closing of the IPO, Chesapeake and GIP conveyed to us a 100 percent membership interest in Chesapeake MLP Operating, L.L.C., which owned all of our assets since September 2009. See Note 1 — Description of Business and Basis of Presentation.
Omnibus Agreement. Upon closing of the IPO, the Partnership entered into an omnibus agreement with Chesapeake Midstream Ventures and Chesapeake Midstream Holdings that addresses the following matters:
| • | Chesapeake’s obligation to provide us with certain rights relating to certain future midstream business opportunities; and |
| • | our right to indemnification for certain liabilities and our obligation to indemnify Chesapeake Midstream Ventures and affiliated parties for certain liabilities. |
General and Administrative Services and Reimbursement. Pursuant to a services agreement, Chesapeake and its affiliates provide certain services including legal, accounting, treasury, human resources, information technology and administration. The employees supporting these operations are employees of CEMI or Chesapeake. The consolidated financial statements for the Partnership and our 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. Prior to October 15, 2008, allocated costs were based on identification of Chesapeake’s resources which provided a direct benefit and the proportionate share of costs based on estimated usage of shared resources and functions. Costs were allocated based on the proportionate share of Chesapeake’s headcount, compensation expense, or net revenues as appropriate for the nature of the charge. All of the allocations are based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if our Predecessor had been operated as a stand-alone entity. Effective October 15, 2008, as part of the terms of a services agreement, the overhead rate charged to our Predecessor became $0.02/mmbtu. Effective June 1, 2009, the allocated charges from Chesapeake were based on the actual costs for the period as opposed to the $0.02/mmbtu fee. 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 $0.03025/Mcf gathered or actual corporate overhead costs. General and administrative charges were $17.0 million and $2.2 million for the year ended December 31, 2010, and three months ended December 31, 2009, for the Partnership. General and administrative charges were $14.6 million and $11.3 million for the nine months ended September 30, 2009, and year ended December 31, 2008, respectively, for our Predecessor.
Additional Services and Reimbursement. At our request, Chesapeake also provides us 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 our business during the one year period prior to September 30, 2009. In any event, Chesapeake has agreed to perform such services using no less than a reasonable level of care in accordance with industry standards.
In connection with the services arrangement, we reimburse GIP for certain costs incurred by GIP in connection with assisting us in the operation of our business. For the year ended December 31, 2010, the cost was $0.9 million for these support services.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The term of the services agreement will extend for additional twelve-month periods unless any party provides 180 days’ prior written notice otherwise prior to the expiration of the initial term ending December 31, 2011 or the applicable twelve-month period; provided that, on December 31, 2011, our general partner has the right to extend the term of the services agreement through June 30, 2012 regardless of any other party providing notice to terminate. In such a situation, the services agreement would automatically terminate on June 30, 2012.
Employee Secondment Agreement. Upon completion of the IPO, Chesapeake, certain of its affiliates and our general partner 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 our business under the direction, supervision and control of the general partner. Additionally, all of our executive officers other than our 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 $30.3 million for the year ended December 31, 2010. These charges include $28.3 million in operating expenses and $2.0 million in general and administrative expenses in the accompanying consolidated statements of operations.
The initial term of the employee secondment agreement extends through September 30, 2014. The term will automatically extend for additional twelve month periods unless any party provides 90 days’ prior written notice otherwise prior to the expiration of the initial term or the applicable twelve month period. Our 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 our general partner, our general partner has entered into a shared services agreement with Chesapeake pursuant to which our general partner reimburses certain of the costs and expenses incurred by Chesapeake in connection with Mr. Stice’s employment. Our general partner is generally expected, subject to certain exceptions, to reimburse Chesapeake for 50 percent of the costs and expenses of the amounts provided to Mr. Stice in his employment agreement; however, the ultimate reimbursement obligation is determined based on the amount of time Mr. Stice actually spends working for us. The reimbursement obligations of our general partner will continue for so long as Mr. Stice is employed by both our general partner and Chesapeake.
Gas Compressor Master Rental and Servicing Agreement. Upon completion of the IPO, the Partnership entered into a gas compressor master rental and servicing agreement with MidCon Compression, LLC, (“MidCon”) a wholly owned indirect subsidiary of Chesapeake, pursuant to which MidCon agreed to lease to us certain compression equipment that we use to compress gas gathered on our gathering systems and provide certain related services. In return for the lease of such equipment, we 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 granted MidCon the exclusive right to lease and rent compression equipment to us in the acreage dedications through September 30, 2016. Thereafter, we will have the right to continue leasing such equipment through September 30, 2019 at market rental rates to be agreed upon between the parties or to lease compression equipment from unaffiliated third parties. MidCon guarantees to us that the leased compressors will meet specified run time and throughput performance guarantees. The monthly rental rates are reduced for any leased equipment that does not meet these guarantees. Compressor rental charges from affiliates were $47.8 million and $11.7 million for the year ended December 31, 2010 and three months ended December 31, 2009, respectively. Compressor rental charges from affiliates were $47.3 million and $47.0 million for the nine months ended September 30, 2009, and year ended December 31, 2008, respectively, for our Predecessor. These charges are included in operating expenses in the accompanying consolidated statements of operations.
We are obligated to maintain general liability and property insurance, including machinery breakdown insurance with respect to the leased equipment. In addition, MidCon has agreed to provide us with emission testing and other related services at monthly rates. We may terminate these services upon not less than six months notice, and MidCon may terminate these services at any time after September 30, 2011 upon not less than six months notice.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
The compression agreement expires on September 30, 2019 but will continue from year to year thereafter, unless terminated by us no less than 60 days prior to the end of the term or any year thereafter. Additionally, either party may terminate in specified circumstances, including upon the other party’s failure to perform material obligations under the compression agreement if such failure is not cured within 60 days after notice thereof.
In connection with the acquisition of the Springridge gathering system, the previously existing above-described gas compressor master rental and servicing agreement was amended and restated, on terms substantially similar to those under the Partnership’s original compression agreement, to include the AMI associated with the Springridge natural gas gathering system and to allow for the addition of future AMIs.
Inventory Purchase Agreement. Upon completion of the IPO, we entered into an inventory purchase agreement pursuant to which we agreed beginning as of September 30, 2009 to purchase from Chesapeake, in each case on terms and conditions to be mutually agreed upon by Chesapeake and us, our first $60.0 million of requirements of pipes that are useful in the conduct of the natural gas gathering, compression, dehydrating, treating and transportation business at a specified price per ton. Through the year ended December 31, 2010, we have purchased approximately $36.6 million of inventory pursuant to this inventory purchase agreement and incorporated in our property, plant and equipment.
Gas Gathering Agreements. We are party to (i) a 20-year gas gathering agreement with certain subsidiaries of Chesapeake that was entered into in connection with the joint venture transaction in September 2009, (ii) a 20-year gas gathering agreement with Total that was entered into in connection with an upstream joint venture transaction between Chesapeake and Total E&P in January 2010, and (iii) a 10-year gas gathering agreement with certain subsidiaries of Chesapeake that was entered into concurrent with the closing of the acquisition of the Springridge gas gathering system in December 2010.
Future revenues under our gas gathering agreements will be derived pursuant to terms that will differ between our three operating regions.
In the event that either Chesapeake or Total sells, transfers or otherwise disposes to a third party properties within the acreage dedication in our Barnett Shale region and, solely with respect to Chesapeake in our Mid-Continent and Haynesville Shale regions, it will be required to cause the third party to either enter into our existing gas gathering agreement with Chesapeake or Total or enter into a new gas gathering agreement with us on substantially similar terms to our existing gas gathering agreement with Chesapeake or Total.
| 6. | Income Taxes |
As discussed in Note 2, as a master limited partnership, we are a pass-through entity and not subject to federal income taxes and most state income taxes with the exception of Texas Franchise Tax. For federal and state income tax purposes other than Texas, all income, expenses, gains, losses and tax credits generate flow through to the owners, and accordingly, do not result in a provision for income taxes. Income tax (benefit) expense for the nine months ended September 30, 2009, and year ended December 31, 2008, is as follows:
| Predecessor | ||||||||
| Nine Months Ended September 30, 2009 |
Year
Ended December 31, 2008 |
|||||||
| (in thousands) | ||||||||
| Current |
$ | — | $ | — | ||||
| Deferred |
6,341 | (61,287 | ) | |||||
| Total income tax (benefit) expense presented in the Statements of Operations |
$ | 6,341 | $ | (61,287 | ) | |||
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Reconciliation of income tax expense at the U.S. Federal Statutory Income Tax Rate to actual tax expense (Statutory Rate Reconciliation) for the nine months ended September 30, 2009, and year ended December 31, 2008, is as follows:
| Predecessor | ||||||||
| Nine Months Ended September 30, 2009 |
Year Ended December 31, 2008 |
|||||||
| ($ in thousands) | ||||||||
| Income tax expense, computed at the statutory rate of 35% |
$ | (3,862 | ) | $ | 36,403 | |||
| Effect of state income tax, net of federal income tax effect |
423 | 1,022 | ||||||
| Effect of non-taxable entities |
9,780 | (12,555 | ) | |||||
| Effect of change in tax status(1) |
— | (86,157 | ) | |||||
| Total income tax expense (benefit) |
$ | 6,341 | $ | (61,287 | ) | |||
| Effective tax rate |
(57.47 | )% | (58.93 | )% | ||||
| (1) | Certain deferred tax liabilities were eliminated and recognized in earnings in 2008 as a result of the change in tax status of our Predecessor and its subsidiaries. |
| 7. | Concentration of Credit Risk |
Chesapeake and Total are the only customers from whom revenues exceeded 10 percent of consolidated revenues for the years ended December 31, 2010, 2009, and 2008, for the Partnership and our Predecessor. The percentage of revenues from Chesapeake, Total and other customers are as follows:
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Chesapeake |
82.2 | % | 98.0 | % | 99.0 | % | ||||||
| Total |
14.8 | % | — | — | ||||||||
| Other |
3.0 | % | 2.0 | % | 1.0 | % | ||||||
| Total |
100 | % | 100 | % | 100 | % | ||||||
Financial instruments that potentially subject the Partnership and our Predecessor to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. On December 31, 2010 and 2009, respectively, cash and cash equivalents were invested in a non-interest bearing account and money market funds with investment grade ratings.
| 8. | Property, Plant and Equipment |
A summary of the historical cost of the Partnership’s property, plant and equipment is as follows:
| Estimated Useful Lives (Years) |
December 31, 2010 |
December 31, 2009 |
||||||||||
| ($ in thousands) | ||||||||||||
| Gathering systems |
20 | $ | 2,544,053 | $ | 2,013,347 | |||||||
| Other fixed assets |
2 through 39 | 41,125 | 34,130 | |||||||||
| Total property, plant and equipment |
2,585,178 | 2,047,477 | ||||||||||
| Accumulated depreciation |
(358,269 | ) | (271,062 | ) | ||||||||
| Total net, property, plant and equipment |
$ | 2,226,909 | $ | 1,776,415 | ||||||||
Included in gathering systems is $329.5 million and $383.8 million at December 31, 2010 and 2009, respectively, that is not subject to depreciation as the systems were under construction and had not been put into service.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
Depreciation expense was $88.4 million and $19.2 million for the year ended December 31, 2010, and three months ended December 31, 2009, respectively, for the Partnership. Depreciation expense was $64.4 million and $46.5 million for the nine months ended September 30, 2009, and year ended December 31, 2008, respectively, for our Predecessor.
| 9. | Business Combinations |
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 consists of 226 miles of gathering pipeline primarily located in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, the Partnership entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication, annual fee redetermination and a minimum volume commitment.
The results of operations presented and discussed in this annual report include results of operations from the Springridge gathering system for the 11-day period from closing of the acquisition on December 21, 2010, through December 31, 2010. For this period, revenues and net loss attributable to Springridge operations were $2.1 million and $1.0 million, respectively. The total purchase price of the Springridge acquisition was allocated as follows: gas gathering system assets of $327.5 million and a customer contract with a value of $172.5 million. The useful life of the customer contract acquired is estimated to be 15 years and is amortized on a straight-line basis.
The following unaudited pro forma condensed consolidated financial statements for the years ended December 31, 2010 and 2009, are based upon the historical consolidated financial statements of the Partnership and the historical results of operations of the Springridge assets. The unaudited pro forma condensed consolidated financial statements have been prepared as if the Springridge acquisition occurred on January 1, 2010, in the case of the unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2010, and as if the Springridge acquisition occurred on January 1, 2009, in the case of the unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2009. The pro forma adjustments reflected in the pro forma condensed consolidated financial statements are based upon currently available information and certain assumptions and estimates; therefore, the actual effects of these transactions will differ from the pro forma adjustments. However, the Partnership’s management considers the applied estimates and assumptions to provide a reasonable basis for the presentation of the significant effects of certain transactions that are expected to have a continuing impact on the Partnership. In addition, the Partnership’s management considers the pro forma adjustments to be factually supportable and to appropriately represent the expected impact of items that are directly attributable to the transfer of the Springridge assets to the Partnership.
| Year Ended December 31, 2010 | ||||||||||||||||||
| Partnership Historical |
Springridge Assets |
Pro Forma Adjustments |
Partnership Pro Forma as Adjusted |
|||||||||||||||
| (in thousands) | ||||||||||||||||||
| Revenues, including revenue from affiliates |
$ | 459,153 | $ | 53,592 | $ | — | $ | 512,745 | ||||||||||
| Total Operating Expenses |
259,047 | 35,151 | 12,899 | (a)(b) | 307,097 | |||||||||||||
| Interest expense |
(2,550 | ) | (107 | ) | (6,937 | ) | (c) | (9,594 | ) | |||||||||
| Other income |
102 | — | — | 102 | ||||||||||||||
| Income tax expense |
(2,431 | ) | — | — | (2,431 | ) | ||||||||||||
| Net income (loss) |
$ | 195,227 | $ | 18,334 | $ | (19,836 | ) | $ | 193,725 | |||||||||
| Limited partner interest in net income |
||||||||||||||||||
| Net income |
$ | 193,725 | ||||||||||||||||
| Less general partner interest in net income |
(3,874 | ) | ||||||||||||||||
| Limited partner interest in net income |
$ | 189,851 | ||||||||||||||||
| Net income per common unit – basic and diluted |
$ | 1.37 | ||||||||||||||||
| Net income per subordinated unit – basic and diluted |
$ | 1.37 | ||||||||||||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
| Year Ended December 31, 2009 | ||||||||||||||||||||
| Partnership Historical |
Springridge Assets |
Pro Forma Adjustments |
Partnership Pro Forma as Adjusted |
|||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| Revenues, including revenue from affiliates |
$ | 383,095 | $ | 29,219 | $ | — | $ | 412,314 | ||||||||||||
| Total Operating Expenses |
325,648 | 17,012 | 12,899 | (a | )(b) | 355,559 | ||||||||||||||
| Interest expense |
(840 | ) | (39 | ) | (7,005 | ) | (c | ) | (7,884 | ) | ||||||||||
| Other income |
9 | — | — | 9 | ||||||||||||||||
| Income tax expense |
(639 | ) | — | — | (639 | ) | ||||||||||||||
| Net income (loss) |
$ | 55,977 | $ | 12,168 | $ | (19,904 | ) | $ | 48,241 | |||||||||||
| Limited partner interest in net income |
||||||||||||||||||||
| Net income |
$ | 48,241 | ||||||||||||||||||
| Less general partner interest in net income |
(965 | ) | ||||||||||||||||||
| Limited partner interest in net income |
$ | 47,276 | ||||||||||||||||||
| Net income per common unit – basic and diluted |
$ | 0.34 | ||||||||||||||||||
| Net income per subordinated unit – basic and diluted |
$ | 0.34 | ||||||||||||||||||
| (a) | The amortization of the customer contract gas gathering agreement signed in connection with the Springridge acquisition. The intangible asset is amortized on a straight-line basis over 15 years. |
| (b) | The incurrence of incremental general and administrative expense per contractual agreement with Chesapeake. The established terms indicate corporate overhead costs will be charged to the Partnership based on a fee per mcf of natural gas gathered. The mcf fee is calculated as the lesser of $0.03/mcf gathered or actual corporate overhead costs. |
| (c) | Interest at 3.01% on the debt incurred to fund the Springridge acquisition. The debt is variable and a 125 basis point increase in the interest rate would have increased interest expense $0.3 million for the twelve months ended December 31, 2010 and 2009. |
Amortization of the intangible asset during each of the next five years is expected to be $11.5 million.
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.
| Year Ended December 31, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| (in thousands) | ||||||||||||
| Asset retirement obligations, beginning of period |
$ | 2,850 | $ | 2,714 | $ | 4,032 | ||||||
| Additions |
229 | — | 1,259 | |||||||||
| Accretion expense |
211 | 136 | 301 | |||||||||
| Deletions |
(412 | ) | — | — | ||||||||
| Asset retirement obligations, end of period |
$ | 2,878 | $ | 2,850 | $ | 5,592 | ||||||
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
11. Debt and Interest Expense
Revolving Bank Credit Facilities. On September 30, 2009, the newly created joint venture closed a new $500 million secured revolving bank credit facility to fund capital expenditures associated with the joint venture’s building of additional natural gas gathering systems and for general corporate purposes. At the same time, our Predecessor amended and restated its existing revolving bank credit facility to reduce its capacity from $460 million to $250 million, among other changes. The outstanding balance under our Predecessor’s credit facility was repaid at the time of the amendment. In conjunction with the establishment of the new facilities, our Predecessor expensed $4 million of previously capitalized debt issuance costs associated with this amendment and capitalized $5.7 million associated with the amended $250 million credit facility. We capitalized $11.5 million of debt issuance costs associated with the $500 million credit facility.
On August 2, 2010, we amended the $500 million joint venture credit facility. The amended revolving bank credit facility matures in July 2015, and provides up to $750.0 million of borrowing capacity, including a sub-limit of $25.0 million for same-day swing line advances and a sub-limit of $50.0 million for letters of credit. In addition, the credit facility contains an accordion feature that allows the Partnership to increase the available borrowing capacity under the facility up to $1.0 billion, subject to the satisfaction of certain closing conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the credit facility. Borrowings under the credit facility are secured by all of the assets of the Partnership and its subsidiaries, and loans thereunder (other than swing line loans) bear interest at the Partnership’s option at either (i) the greater of the reference rate of Wells Fargo Bank, NA, the federal funds effective rate plus 0.50 percent, and the one-month London Interbank Offered Rate (“LIBOR”) plus 1.00 percent, all of which is subject to a margin that varies from 1.75 percent to 2.25 percent per annum according to the most recent consolidated leverage ratio (as defined) or (ii) the Eurodollar rate, which is based on the LIBOR plus a margin that varies from 2.75 percent to 3.25 percent per annum according to the most recent consolidated leverage ratio. The unused portion of the credit facility is subject to a commitment fee of 0.50 percent per annum according to the most recent consolidated leverage ratio. At December 31, 2010, there were $249.1 million outstanding borrowings under such credit facility leaving available borrowing capacity of $500.9 million. The average weighted interest rates for the outstanding balances of the revolving credit facility, were 3.99 percent and 3.90 percent for the years ended December 31, 2010 and 2009, respectively.
The Partnership’s amended credit facility agreement requires maintenance of an indebtedness to EBITDA ratio (as defined in the amended credit facility agreement) of not more than 4.50 to 1, and an EBITDA to interest expense ratio (as defined in the amended credit facility agreement) of not less than 3.00 to 1. The Partnership was in compliance with all covenants under the agreement at December 31, 2010.
Additionally, the credit facility contains various covenants and restrictive provisions which, among other things, limits the ability of the Partnership and its subsidiaries to incur additional indebtedness, make investments or loans, create liens and pay dividends or distributions. 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 credit facility could be declared immediately due and payable. The credit facility agreement also has cross default provisions that apply to any other indebtedness the Partnership has with an outstanding principal amount in excess of $15 million.
Fair Value
Estimated fair values are determined by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. Based on the borrowing rates available at December 31, 2010 for debt with similar terms and maturities, the carrying value of long-term debt approximates its fair value.
Capitalized Interest
Interest expense was net of capitalized interest of $2.6 million, $0.3 million, and $6.5 million for the year ended December 31, 2010, three months ended December 31, 2009, and nine months ended September 30, 2009, respectively, for the Partnership and our Predecessor. There was no interest capitalized for the year ended December 31, 2008.
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
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, 2010 or 2009.
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 $50.1 million, $11.7 million, $48.2 million, and $49.9 million for the year ended December 31, 2010, three months ended December 31, 2009, nine months ended September 30, 2009, and year ended December 31, 2008, respectively, for the Partnership and our Predecessor. The Partnership’s’ remaining contractual lease obligations as of December 31, 2010 represent obligations with an affiliate of Chesapeake for compression equipment as compression services are needed to support pipeline that is being placed in service in future periods.
Future minimum rental payments due under operating leases as of December 31, 2010 are as follows:
| (in thousands) | ||||
| 2011 |
$ | 57,007 | ||
| 2012 |
43,819 | |||
| 2013 |
6,555 | |||
| 2014 |
4,601 | |||
| 2015 |
1,132 | |||
| Thereafter |
— | |||
| Future minimum lease payments |
$ | 113,114 | ||
13. Recently Issued Accounting Standards
The Financial Accounting Standards Board (“FASB”) recently issued the following standards which we reviewed to determine the potential impact on our financial statements upon adoption.
In February 2010, the FASB amended its guidance on subsequent events to remove the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. The guidance was effective upon issuance. We adopted this guidance in 2010.
The FASB also issued new guidance requiring additional disclosures about fair value measurements, adding a new requirement to disclose transfers in and out of Levels 1 and 2 measurements and gross presentation of activity within a Level 3 roll forward. The guidance also clarified existing disclosure requirements regarding the level of disaggregation of fair value measurements and disclosures regarding inputs and valuation techniques. We determined that this guidance had no impact on our financial position or results of operations upon adoption. Required disclosures for the reconciliation of purchases, sales, issuance and settlements of financial instruments valued with a Level 3 method are effective beginning on January 1, 2011, and we do not expect the implementation to have a material impact on our financial position or results of operations. See Note 2 for discussion regarding fair value measurements.
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CHESAPEAKE MIDSTREAM PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)
In December 2010, the FASB issued guidance on disclosure of supplementary pro forma information for business combinations. The guidance specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The guidance also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, non-recurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenues and earnings. These amendments are effective prospectively for business combinations with an acquisition date on or after December 15, 2010, however, early adoption is permitted.
| 14. | Subsequent Event |
On January 31, 2011, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.3375 per unit, or $47.6 million in aggregate. The cash distribution was paid on February 14, 2011 to unitholders of record at the close of business on February 10, 2011.
| 15. | Quarterly Financial Data (Unaudited) |
Summarized unaudited quarterly financial data for 2010 and 2009 are as follows ($ in thousands except per share data):
| Quarters Ended | ||||||||||||||||
| March 31, 2010 |
June 30, 2010 |
September 30,
2010 |
December 31, 2010 |
|||||||||||||
| Total revenues |
$ | 95,386 | $ | 101,239 | $ | 100,060 | $ | 162,468 | ||||||||
| Gross profit(a) |
$ | 64,693 | 68,854 | 65,966 | 126,347 | |||||||||||
| Net income attributable to Chesapeake Midstream Partners, L.P(b) . |
$ | n/a | n/a | 19,514 | 89,882 | |||||||||||
| Net income per limited partner unit(b) |
$ | n/a | n/a | 0.14 | 0.64 | |||||||||||
| Quarters Ended | ||||||||||||||||
| Predecessor | ||||||||||||||||
| March 31, 2009 |
June 30, 2009 |
September 30, 2009 |
December 31, 2009 |
|||||||||||||
| Total revenues |
$ | 110,034 | $ | 117,629 | $ | 131,258 | $ | 107,377 | ||||||||
| Gross profit(a) |
$ | 61,565 | 71,621 | 79,131 | 75,503 | |||||||||||
| Net income attributable to Chesapeake Midstream Partners, L.P(b) . |
$ | n/a | n/a | n/a | n/a | |||||||||||
| Net income per limited partner unit(b) |
$ | n/a | n/a | n/a | n/a | |||||||||||
| (a) | Total revenue less operating costs. |
| (b) | Reflective of general and limited partner interest in net income since closing the Partnership’s IPO on August 3, 2010. See Note 4 to the consolidated financial statements. |
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| ITEM 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
| ITEM 9A. | Controls and Procedures |
As required by Rule 13a-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 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 and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. 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 as of December 31, 2010.
This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the Partnership’s registered public accounting firm due to a transition period established by rules of the SEC for newly public companies.
Changes in Internal Controls
No changes in the Partnership’s internal control over financial reporting occurred during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.
| ITEM 9B. | Other Information |
Not applicable.
| ITEM 10. | Directors, Executive Officers and Corporate Governance |
Management of the Partnership
Board of Directors
As a limited partnership, we have no directors or officers. Instead, Chesapeake Midstream GP, L.L.C., our general partner, manages our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. However, 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. Our general partner, therefore, may cause us to incur indebtedness or other obligations that are nonrecourse to it.
The directors of our general partner oversee our operations. Chesapeake Midstream Ventures, which is jointly and equally owned by Chesapeake and GIP, is the sole member of our general partner and has the right to appoint our general partner’s entire board of directors. Our general partner has seven directors, two of whom are designated by Chesapeake, two of whom are designated by GIP and three of whom are independent as defined under the independence standards established by the NYSE and the Exchange Act. Our general partner’s board of directors has affirmatively determined that David A. Daberko, Philip L. Fredrickson and Suedeen G. Kelly satisfy the NYSE and SEC requirements for independence. 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 a compensation committee.
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Evaluation of director candidates includes assessment of whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct the affairs and business of the partnership, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.
We have no minimum qualifications for director candidates. In general, however, we review and evaluate both incumbent and potential new directors in an effort to achieve diversity of skills and experience among our directors and in light of the following criteria:
| • | experience in business, government, education, technology or public interests; |
| • | high-level managerial experience in large organizations; |
| • | breadth of knowledge regarding our business or industry; |
| • | specific skills, experience or expertise related to an area of importance to us, such as energy production, consumption, distribution or transportation, government, policy, finance or law; |
| • | moral character and integrity; |
| • | commitment to our unitholders’ interests; |
| • | ability to provide insights and practical wisdom based on experience and expertise; |
| • | ability to read and understand financial statements; and |
| • | ability to devote the time necessary to carry out the duties of a director, including attendance at meetings and consultation on partnership matters. |
Qualified candidates for nomination to the board are considered without regard to race, color, religion, gender, ancestry or national origin.
Board Leadership Structure and Role in Risk Oversight
Mr. Daberko currently serves as chairman of our general partner’s board of directors. Our general partner’s board of directors believes that no single organizational structure is best and most effective in all circumstances. Accordingly, the board retains the flexibility to determine the organizational structure that best enables the partnership to confront the challenges and risks it faces. Although our general partner’s chief executive officer currently does not serve as a member of our general partner’s board of directors, we currently have no policy prohibiting any current or future executive officer from serving as a member of the board, including as its chairman. Members of our general partner’s board of directors are designated or elected by the sole member of our general partner, Chesapeake Midstream Ventures.
It is management’s responsibility, subject to the oversight our general partner’s board of directors, to monitor and, to the extent possible, mitigate the negative impact of uncertainty in the business environment on our operations and our financial objectives. Our general partner maintains an enterprise risk management (“ERM”) program overseen by its management-level Risk Management Committee, which is comprised of our general partner’s Chief Operating Officer, Chesapeake’s Vice President of Risk Management, our general partner’s Director of Environmental Health and Safety, and our general partner’s Lead Counsel. Significant risks and the possible approaches to mitigate such risk 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, hedging policy, significant acquisitions and divestitures, capital markets transactions and the delegation of authority to our management.
Committees
Our general partner’s board of directors has three standing committees: the audit committee, conflicts committee and compensation committee.
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Audit Committee. The audit committee is comprised 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. In making the independence determination, the board considered the requirements of the NYSE and our Corporate Governance Guidelines. The audit committee held three meetings in 2010.
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 is comprised of three independent members of our general partner’s board of directors, Messrs. Daberko and Frederickson and Ms. Kelly. Mr. Frederickson is the current chairman of the conflicts committee. The conflicts committee reviews specific matters that the board believes may involve conflicts of interest (including certain transactions with Chesapeake, GIP and/or Chesapeake Midstream Ventures) and which it determines to submit to the conflicts committee for review. The conflicts committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Chesapeake, GIP and/or Chesapeake Midstream Ventures, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. The conflicts committee held seven meetings in 2010.
Compensation Committee. The compensation committee is comprised of three members of our general partner’s board of directors, Matthew C. Harris, Marcus C. Rowland and Ms. Kelly. Ms. Kelly is the current chairman of the compensation committee. The compensation committee oversees compensation decisions for the officers of our general partner and administers the LTIP 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 one meeting in 2010.
Executive Officers
The officers of our general partner manage and conduct our operations. All of the executive officers of our general partner, other than J. Mike Stice, the Chief Executive Officer of our general partner, devote all of their time to manage and conduct our operations. Mr. Stice allocates his time between managing our business and affairs and certain business and affairs of Chesapeake and, as such, may face a conflict regarding the allocation of his time between our business and other business interests of Chesapeake. In 2010, Mr. Stice devoted approximately half of his time to our business, although we expect the amount of time that he devotes may increase or decrease in the future as our business develops. The officers of our general partner and other Chesapeake employees operate our business and provide us with general and administrative services pursuant to the services agreement and the employee secondment agreement and, in the case of Mr. Stice, the shared services agreement, each as described in “Item 13. Certain Relationships and Related Transactions, and Director Independence—Agreements with Affiliates—Employee Secondment Agreement,” “—Services Agreement” and “—Shared Services Agreement.”
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Our general partner does not receive any management fee or other compensation for its management of our partnership under the omnibus agreement, the services agreement, the employee secondment agreement or otherwise. Under the services agreement, Chesapeake performs centralized corporate functions for us. In return for such general and administrative services, our general partner has agreed to reimburse Chesapeake on a monthly basis for the time and materials actually spent in providing general and administrative support to our operations. Our reimbursement to Chesapeake of such general and administrative expenses in any given month is subject to a cap in an amount equal to $0.03025 per Mcf multiplied by the volume (measured in Mcf) of natural gas that we gather, transport or process in such month. The $0.03025 per Mcf cap is subject to an annual upward adjustment on October 1st of each year equal to 50% of any increase in the Consumer Price Index, and, subject to receipt of requisite approvals, such cap may be further adjusted to reflect changes in the general and administrative services provided by Chesapeake relating to new laws or accounting rules that are implemented. Please read “Item 13. Certain Relationships and Related Transactions, and Director Independence—Agreements with Affiliates—Services Agreement.” In addition, under the employee secondment agreement, specified employees of Chesapeake are seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Our general partner, subject to specified exceptions and limitations, reimburses Chesapeake on a monthly basis for substantially all costs and expenses it incurs relating to such seconded employees. Please read “Item 13. Certain Relationships and Related Transactions, and Director Independence—Agreements with Affiliates—Employee Secondment Agreement.”
Directors and Executive Officers
The following table shows information regarding the current executive officers and directors of our general partner. Directors are appointed for a term of one year. The directors hold office until their successors have been duly elected and qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board of directors. There are no family relationships among any of our general partner’s directors or executive officers.
| Name |
Age | Position with Chesapeake Midstream GP, L.L.C. | ||
| J. Mike Stice |
51 | Chief Executive Officer | ||
| David C. Shiels |
45 | Chief Financial Officer | ||
| Robert S. Purgason |
54 | Chief Operating Officer | ||
| Matthew C. Harris |
50 | Director | ||
| Aubrey K. McClendon |
51 | Director | ||
| Marcus C. Rowland |
58 | Director | ||
| William A. Woodburn |
60 | Director | ||
| David A. Daberko |
65 | Director | ||
| Philip L. Frederickson |
54 | Director | ||
| Suedeen G. Kelly |
59 | Director |
J. Mike Stice has served as Chief Executive Officer of our general partner since January 2010. Mr. Stice was appointed Senior Vice President—Natural Gas Projects of Chesapeake Energy Corporation and President and Chief Operating Officer of Chesapeake’s primary midstream subsidiaries in November 2008. Prior to joining Chesapeake, Mr. Stice spent 27 years with ConocoPhillips and its predecessor companies, where he most recently served as President of ConocoPhillips Qatar, responsible for the development, management and construction of natural gas liquefaction and regasification (LNG) projects. While at ConocoPhillips, he also served as Vice President of Global Gas LNG, as President of Gas and Power and as President of Energy Solutions in addition to other roles in ConocoPhillips’ midstream business units. Mr. Stice graduated from the University of Oklahoma in 1981 and from Stanford University in 1995.
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.
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Robert S. Purgason has served as Chief Operating Officer of our general partner since January 2010. Prior to joining our general partner, Mr. Purgason spent five years at Crosstex Energy Services, L.P. and was promoted to Executive 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 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 the corporation and President of National City Bank in Cleveland. He served as President and Chief Operating Officer from 1993 until 1995 when he was named Chairman and Chief Executive Officer. He retired as Chief Executive Officer in June 2007 and as Chairman in December 2007. Mr. Daberko also serves on the Board of Directors of RPM International, Inc. (NYSE: RPM) and Marathon Oil Corporation (NYSE: MRO). He is a trustee of Case Western Reserve University, University Hospitals Health System and Hawken School. Mr. Daberko also previously served, within the last five years, as a director of National City Corporation and OMNOVA Solutions, Inc. Mr. Daberko graduated from Denison University in 1967 and from Case Western Reserve University in 1970. We believe that Mr. Daberko’s extensive financial industry background, particularly the leadership and management skills he acquired while serving as a chief executive officer, brings important experience and skill to the board.
Philip L. Frederickson has served as a director of our general partner since August 2010. Mr. Frederickson retired from ConocoPhillips (NYSE: COP) after 29 years of service with the company. At the time of his retirement he was Executive Vice President Planning, Strategy and Corporate Affairs. He also served as a board member for Chevron Phillips Chemical and DCP Midstream. Mr. Frederickson joined Conoco in 1978 and held several senior positions in the United States and Europe, including General Manager, Strategy and Business Development, Refining and Marketing Europe; Managing Director, Conoco Ireland; General Manager, Refining and Marketing, Rocky Mountain region; General Manager, Strategy and Portfolio Management, Upstream; and Vice President, Business Development. Mr. Frederickson was Senior Vice President of Corporate Strategy and Business Development for Conoco Inc. from 2001 to 2002. Following the announcement of the merger of Conoco and Phillips in 2001, Mr. Frederickson was named integration lead to coordinate the merger transition and in 2002 was made Executive Vice President, Commercial, of ConocoPhillips. Mr. Frederickson serves as a board member for Rosetta Resources Inc. (NASDAQ: ROSE), Sunoco Logistics (NYSE: SXL) and the Yellowstone Park Foundation and is a member of the Texas Tech University Engineering Dean’s Council. Mr. Frederickson graduated from Texas Tech University in 1978. We believe that Mr. Frederickson’s extensive energy industry background, particularly his expertise in corporate strategy and business development, brings important experience and skill to the board.
Matthew C. Harris has served as a director of our general partner since January 2010. Mr. Harris is currently a partner of GIP leading GIP’s energy/waste industry investment team globally. He is a member of the board of GIP and of its Investment and Portfolio Valuation Committees. Prior to the formation of GIP in 2006, Mr. Harris was a Managing Director in the Investment Banking Department at Credit Suisse. Most recently, he was Co-Head of the Global Energy Group and Head of the EMEA Emerging Markets Group. Prior to 2003, Mr. Harris was a senior member of the Mergers and Acquisitions Group and served as Co-Head of Americas M&A. From 1984 to 1994, he was a senior member of the Mergers and Acquisitions Group of Kidder Peabody & Co. Incorporated. Mr. Harris is a director of the GIP portfolio companies Biffa and Ruby Pipeline Holding Company LLC. Mr. Harris graduated from the University of California at Los Angeles in 1984. We believe that Mr. Harris’ extensive energy industry background, particularly his expertise in mergers and acquisitions, brings important experience and skill to the board.
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Suedeen G. Kelly has served as a director of our general partner since August 2010. Ms. Kelly is a former Commissioner of the Federal Energy Regulatory Commission. Ms. Kelly was nominated by both Presidents Bush and Obama to three terms as Commissioner of the Federal Energy Regulatory Commission from 2003 to 2009. In 2000, she worked as Regulatory Counsel to the California Independent System Operator. In 1999, 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 regulatory matters, brings important experience and skill to the board.
Aubrey K. McClendon has served as a director of our general partner since January 2010. Mr. McClendon has served as Chairman of the Board, Chief Executive Officer and a director of Chesapeake since co-founding Chesapeake in 1989. From 1982 to 1989, Mr. McClendon was an independent producer of oil and natural gas. Mr. McClendon graduated from Duke University in 1981. We believe that Mr. McClendon’s extensive energy industry background and relationship with Chesapeake, particularly his leadership skills in serving as Chairman of the Board and Chief Executive Officer of Chesapeake and his instrumental role in the formulation and promotion of national and local initiatives that promote American natural gas as the best solution for our nation’s future energy needs, bring important experience and skill to the board.
Marcus C. Rowland has served as a director of our general partner since January 2010. Mr. Rowland currently serves as President and Chief Financial Officer of Frac Tech Services, LLC. Prior to joining Frac Tech in November 2010, Mr. Rowland was an Executive Vice President of Chesapeake from 1998 to November 2010 and its Chief Financial Officer from 1993 to November 2010. He served as Senior Vice President of Chesapeake from 1997 to 1998 and as Vice President—Finance from 1993 until 1997. From 1990 until he joined Chesapeake, Mr. Rowland was Chief Operating Officer of Anglo-Suisse, L.P. assigned to the White Nights Russian Enterprise, a joint venture of Anglo-Suisse, L.P. and Phibro Energy Corporation, a major foreign operation which was granted the right to engage in oil and gas operations in Russia. Prior to his association with White Nights Russian Enterprise, Mr. Rowland owned and managed his own natural gas and oil company and prior to that was Chief Financial Officer of a private exploration company in Oklahoma City from 1981 to 1985. Mr. Rowland is a Certified Public Accountant. Mr. Rowland graduated from Wichita State University in 1975. We believe that Mr. Rowland’s extensive energy industry background, particularly his financial reporting and oversight 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 the board of GE Capital from 2000 to 2001. Mr. Woodburn joined General Electric in 1984 and held leadership positions at GE Lighting (1984-1993) and GE Superabrasives (1994-2000). Prior to joining General Electric, Mr. Woodburn held process engineering and marketing positions at Union Carbide’s Linde Division for five years and was an engagement manager at McKinsey & Company for four years focusing on energy and transportation industries. Mr. Woodburn is a director of the GIP portfolio companies Biffa, Gatwick Airport Limited and Terra-Gen Power Holdings, LLC. Mr. Woodburn graduated from the U.S. Merchant Marine Academy in 1973 and from Northwestern University in 1975. We believe that Mr. Woodburn’s extensive energy industry background, particularly the leadership skills he developed while serving in several executive positions, brings important experience and skill to the board.
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.
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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, 2010.
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”) which 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, the Partnership will disclose the information on its Internet website. Our general partner has also adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance.
We make available free of charge, within the “Corporate Governance” subsection of the “Investors” section of our website at http://www.chkm.com/Investors/Pages/CorporateGovernance.aspx, and in print to any unitholder who so requests, the Code of Ethics, Corporate Governance Guidelines, our audit committee charter, our conflicts committee charter and our compensation committee charter. Requests for print copies may be directed to Dave Shiels at dave.shiels@chk.com or to: Investor Relations, Chesapeake Midstream Partners, L.P., 900 N.W. 63rd Street, Oklahoma City, Oklahoma 73118, or telephone (405) 935-6224. We will post on our Internet 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 Internet 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.
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 and fax number: Name of the Director(s), c/o Marc D. Rome, Assistant Corporate Secretary, Chesapeake Midstream Partners, L.P., 900 N.W. 63rd Street, Oklahoma City, Oklahoma 73118, fax number (405) 849-6282.
| 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 2010 consisting of the following individuals: (1) J. Michael Stice, Chief Executive Officer; (2) David C. Shiels, Chief Financial Officer; and (3) Robert S. Purgason, Chief Operating Officer.
Overview
We do not directly employ any of the persons responsible for managing our business. Our general partner manages our operations and activities, and it, together with its board of directors and officers, makes decisions on our behalf. Chesapeake, subject to the approval of the compensation committee of our general partner’s board of directors, has decision-making authority with respect to the total compensation of individuals whose aggregate annual compensation exceeds $300,000. Chesapeake has also entered into employment agreements with our named executive officers, which are described below.
Chesapeake Midstream Management, L.L.C., a subsidiary of Chesapeake, adopted the Chesapeake Midstream Management Incentive Compensation Plan (“MICP”) in January 2010. Awards under the MICP have been, and may be granted in the future, to certain of our named executive officers, as described below. Outstanding awards under the MICP were made by the board of managers of Chesapeake Midstream Ventures.
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The compensation of Chesapeake’s employees who perform services on our behalf (other than the LTIP and MICP benefits described below), including the named executive officers, are approved by Chesapeake’s management. Awards to the named executive officers under our LTIP are recommended by Chesapeake’s management and approved by the board of directors of our general partner. The officers of our general partner, as well as the employees of Chesapeake who provide services to us, may also participate in employee benefit plans and arrangements sponsored by Chesapeake, including plans that may be established in the future. Our reimbursement for the compensation of 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 2010 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 herein as paid or awarded to Mr. Stice in 2010 reflects only the portion of compensation expense that is or will be payable by us pursuant to the terms of the shared services agreement.
2010 Performance Review
Under the leadership of our Chief Executive Officer, we believe that the consistent effort of the NEOs in 2010 positioned the Partnership to generate strong performance for our unitholders. We believe the success of these efforts has been reflected in our unit price, which, as of March 7, 2011, had increased by 24% since our IPO, and more importantly will be reflected in our unit price over the next several years. Accordingly, these efforts were the primary basis used to establish the compensation for the named executive officers in 2010.
Set forth below are highlights of the Partnership’s performance during 2010:
| • | Completed our IPO of 24,437,500 common units (amount includes 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option on August 3, 2010) at a price of $21.00 per unit. We received gross offering proceeds of approximately $513.2 million less approximately $38.6 million for underwriting discounts and commissions, structuring fees and offering expenses. |
| • | Acquired the Springridge gas gathering system and related facilities from Chesapeake Midstream Development, L.P., a wholly owned subsidiary of Chesapeake, for $500.0 million, which consists of 226 miles of gathering pipeline in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, we entered into a 10-year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication, annual fee redetermination and a three-year minimum volume commitment. |
| • | Maintained stable cash flows and declared cash distributions for the 2010 third and fourth quarters equal to $1.35 per unit on an annualized basis. |
Role of the Named Executive Officers in Setting Compensation
Mr. Stice provides recommendations to Chesapeake and the compensation committee of the board of directors of our general partner with respect to the compensation levels of Messrs. Shiels and Purgason based on a comprehensive, subjective evaluation of the Partnership’s performance and their individual performance. However, final compensation decisions with respect to the named executive officers are made by Chesapeake, subject to approval of the compensation committee of the board of directors of our general partner.
Compensation Committee of our General Partner’s Board of Directors
The compensation committee of our general partner’s board of directors is currently comprised of three members. 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. The compensation committee currently believes that it is appropriate for the elements and mix of each of the named executive officer’s compensation to be structured in a manner similar to how Chesapeake compensates its executive officers, which has been formalized within each named executive officer’s respective employment agreement.
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The following discussion relating to compensation paid by Chesapeake (except for the discussion related to our MICP) is based on information provided to us by Chesapeake and does not purport to be a complete discussion and analysis of Chesapeake’s executive compensation philosophy and practices. The elements of compensation discussed below, and Chesapeake’s decisions with respect to future changes to the levels of such compensation related to the named executive officers, are subject to the approval of our general partner.
Executive Compensation Philosophy
Chesapeake believes strongly that its executive officers should be paid for performance, but has determined that utilizing an objective set of metrics to drive executive compensation suffers from measurement problems and incentivizes behavior that is likely to be contrary to the long-term interests of Chesapeake and its shareholders. Chesapeake’s fundamental business process requires its executive officers to identify and incorporate in Chesapeake’s strategy a number of different variables, the relative importance of which change frequently over short time periods, including but not limited to, energy prices, new discoveries, new technology, interest rates and capital availability. The success Chesapeake’s executive officers have in executing Chesapeake’s strategic business plan is critically important to Chesapeake’s long-term performance. On the other hand, successful execution of the strategic business plan has less impact on Chesapeake’s stock price over short and intermediate time periods than natural gas and oil prices, which are highly volatile and generally driven by factors that the executive officers cannot control. Accordingly, financial and operational performance metrics, including the price of Chesapeake’s common stock or net income, are frequently not effective indicators of the performance of Chesapeake’s executive officers over a one-year horizon. Instead, Chesapeake takes a comprehensive, subjective approach in determining the mix and level of executive compensation. Chesapeake believes this philosophy balances its objective of paying for performance with its objective of attracting, retaining and motivating executive officers with the competence, knowledge, leadership skills and experience to promote Chesapeake’s long-term growth and profitability.
Compensation Design and Process
Chesapeake’s compensation system is designed to:
| • | attract, retain and motivate executive officers with the competence, knowledge, leadership skills and experience to grow the company’s profitability; |
| • | align the interests of its executive officers with the interests of its shareholders by basing a significant majority of each executive officer’s total compensation on individual and corporate performance; and |
| • | encourage both a short-term and long-term focus, while avoiding excessive risk taking. |
Chesapeake reviews each executive officer’s performance twice each year because it believes that frequent performance reviews permit it to monitor the performance of its executive officers and to better understand the business issues facing them. Chesapeake takes a comprehensive approach in determining the mix and level of executive compensation by making an overall assessment of the performance of the executive officers and the role and relative contribution of each executive officer. For the reasons explained above under “Executive Compensation Philosophy”, this approach consists of a subjective consideration of each executive officer’s overall role in the organization, not on individual, predetermined metrics or data points. This assessment also includes recognizing the current value created from good work in prior years and anticipating value to be created in the future through current efforts. In its assessment of the performance of each executive officer, Chesapeake considers the following:
| • | Individual Performance: for example, the executive officer’s contributions to the development and execution of Chesapeake’s business plan and strategies (including contributions that are expected to provide substantial benefit to Chesapeake in future periods), performance of the executive officer’s department or functional unit, level of responsibility and longevity with Chesapeake; |
| • | Company Performance: the overall performance of Chesapeake, including progress made with respect to production, reserves, operating costs, drilling results, risk management activities, asset acquisitions and asset monetizations as well as financial performance as measured by cash flow, net income, cost of capital, general and administrative costs and common stock price performance; and |
| • | Intangibles: including leadership ability, demonstrated commitment to the organization, motivational skills, attitude and work ethic. |
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Chesapeake has not historically utilized any specific tools or contracted for services to benchmark total compensation or components of compensation to peer companies or other benchmarks. Nevertheless, Chesapeake does review and consider the executive compensation systems of its peers at least annually to ensure its compensation systems remain competitive, although it does not specifically target a percentile or range within its peer group’s compensation. Due to Chesapeake’s continuing rapid growth and to pursue best practices, in early 2011 Chesapeake’s compensation committee retained an independent compensation consultant to review its current compensation system and provide recommendations to the Chesapeake compensation committee with respect to future improvements.
Elements and Mix of Compensation
Chesapeake provides short-term compensation in the form of base salaries and cash bonuses and long-term compensation in the form of Chesapeake restricted stock awards and 401(k) matching contributions. However, under the terms of the employee secondment agreement, Messrs. Shiels and Purgason are not eligible to receive Chesapeake restricted stock awards, and, instead, their interests in the MICP and awards that are made under our LTIP provide them with equity-related incentive compensation. Additionally, Chesapeake’s more highly-compensated employees, including Mr. Stice, are 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 Chesapeake’s executive officers are intended to contribute less to total compensation than incentive awards and reflect each executive officer’s base level of responsibility, leadership, tenure and contribution to the success and profitability of Chesapeake. Base salaries tend to be less variable over time.
Cash bonuses make up a greater portion of total executive officer compensation and are intended to provide incentives based on a subjective evaluation of the performance of Chesapeake and the individual over a shorter period than the equity compensation listed below. Cash bonuses are discretionary and generally not awarded pursuant to a formal plan or an agreement with any executive officer.
Each of Messrs. Stice, Shiels and Purgason have entered into employment agreements with Chesapeake, as further described below under “Employment Agreements” below. Pursuant to his employment agreement, Mr. Stice is entitled to certain guaranteed minimum salary levels and annual cash bonuses. Pursuant to their respective employment agreements, Messrs. Shiels and Purgason are entitled to certain minimum cash salary levels and target levels for discretionary cash bonuses. Additionally, discretionary bonuses above the applicable guaranteed or target bonus amounts may be made, in cash, to the named executive officers based on their performance reviews. Such reviews occur semi-annually and are based on a subjective evaluation of performance during the six-month review period. In 2010, Messrs. Shiels and Purgason were granted a cash bonus at their respective target cash bonus levels based on a subjective evaluation of the Partnership’s overall strong performance and their significant individual contributions to the Partnership’s achievements (as described above under “2010 Performance Review”).
Restricted Stock
The stock-based compensation of Chesapeake’s executive officers is intended to make up the largest portion of the total compensation mix and provides incentives for long-term performance that increases shareholder value by aligning the interests of its shareholders and the executive officers. Restricted stock, with a ratable vesting period of four years, is awarded to Chesapeake employees, including its executive officers, on the first trading day of each January and July as part of Chesapeake’s semi-annual review of employee compensation. Chesapeake awards restricted stock, rather than stock options, because the annual stock usage rate or “burn rate” is smaller with restricted stock than with stock options thereby reducing the dilutive effect of stock compensation to its shareholders. Moreover, restricted stock is easier for employees to value than stock options thereby better facilitating long-term employee stock ownership.
Chesapeake’s executive officers have the opportunity to earn restricted stock based on a comprehensive subjective evaluation of Chesapeake’s performance and the individual during the immediately preceding six-month review period in light of the considerations described above under “Compensation Design and Process,” rather than based on predetermined objective company or individual performance factors or metrics.
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Under the shared services agreement concerning Mr. Stice, we reimburse Chesapeake with respect to restricted stock awards called for under the terms of Mr. Stice’s employment agreement but not any discretionary restricted stock awards. As mentioned above, Messrs. Shiels and Purgason are not eligible to receive Chesapeake restricted stock awards based on a restriction in the employee secondment agreement. Each of Messrs. Stice, Shiels and Purgason are eligible to receive awards under our LTIP, which is described below under “Long-Term Incentive Plan,” but no awards were granted to the named executive officers in 2010 because the plan was adopted contemporaneously with the Partnership’s IPO, which occurred after the June 2010 performance review. Awards under the LTIP were granted to each of Messrs. Stice, Shiels and Purgason in January 2011.
Management Incentive Compensation Plan Awards
Chesapeake Midstream Management, L.L.C. adopted the MICP in January 2010. Because Messrs. Shiels and Purgason were first employed by Chesapeake in December 2009 and January 2010, respectively, in terms of equity-related compensation, we provided them only with awards under the MICP in 2010 in order to most closely align their interests with our success (in terms of distributions and unit value).
As described in greater detail below under “Management Incentive Compensation Plan,” and in “Narrative Disclosure for Grants of Plan-Based Awards in 2010,” the MICP generally provides cash-based incentive compensation awards to MICP participants comprised of two components:
| • | the “Excess Return Component,” and |
| • | the “Equity Uplift Component.” |
In 2010, Messrs. Shiels and Purgason were assigned a 0.125% and 0.25% participation interest, respectively, for each of the Equity Uplift Component and the Excess Return Component under the MICP. Mr. Purgason’s percentage level is greater than Mr. Shiels in recognition of Mr. Purgason’s broad-ranging responsibilities and extensive industry experience. No payments under the MICP became due in 2010.
Other Compensation Arrangements
Chesapeake also provides compensation in the form of personal benefits and perquisites to executive officers. Most of the benefits that Chesapeake provides to executive officers are the same benefits that are provided to all employees or large groups of senior-level employees, including health and welfare insurance benefits, 401(k) matching contributions (up to 15% 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. In 2010, Messrs. Shiels and Purgason also received certain benefits associated with their relocation to Oklahoma City.
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Compensation Committee Report
The Compensation Committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth above. Based on the review and discussion, the Committee recommended to the board of directors of Chesapeake Midstream GP, L.L.C. that the Compensation Discussion and Analysis be included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2010.
Members of the Compensation Committee:
Suedeen G. Kelly, Chairman
Matthew C. Harris
Marcus C. Rowland
Employment Agreements
Messrs. Stice, Shiels and Purgason have entered into employment agreements that govern the terms and conditions of their employment, including their duties and responsibilities, compensation and benefits, and applicable severance terms which are described below under “Executive Compensation—Potential Payments Upon Termination or Change of Control.” 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 our employment agreements are integral to our ability to recruit and retain the high caliber of professionals that are critical to the successful execution of our business strategy.
Mr. Stice is employed by Chesapeake Energy Corporation and his services are shared with us, and we share in the expenses of his compensation under a shared services agreement. Messrs. Shiels and Purgason are employed by Chesapeake Midstream Management L.L.C. but their services are wholly dedicated to us under an employee secondment agreement, which also governs our obligation to reimburse Chesapeake Midstream Management L.L.C. for the cost of their compensation and benefits. The shared services agreement and employee secondment agreement are further described in “Item 13. Certain Relationships and Related Transactions, and Director Independence—Agreements with Affiliates—Shared Services Agreement” and “—Employee Secondment Agreement.”
Agreement with J. Mike Stice
Mr. Stice’s employment agreement was originally entered into effective as of October 5, 2008, was amended and restated effective as of November 10, 2008, and was subsequently amended on September 30, 2009. His employment agreement has a three-year term. Pursuant to the shared services agreement, our general partner is generally expected, subject to certain exceptions, to reimburse Chesapeake for 50% of the costs and expenses of the amounts provided to Mr. Stice in his employment agreement; however, the ultimate reimbursement obligation is determined based on the amount of time Mr. Stice actually spends working for us.
The agreement provides for Mr. Stice’s service as the Chief Executive Officer of our general partner with an annual base salary of $500,000 in 2010, which increased to $600,000 in 2011. Mr. Stice is entitled to guaranteed annual bonuses for calendar years 2010 and 2011, in the amount of $350,000 and $425,000, respectively, payable by January 31 of the following year, provided Mr. Stice remains employed on the bonus payment dates. Additional, discretionary bonuses may also be made. Mr. Stice is also entitled to participate in the employee benefit plans and arrangements, such as retirement and health plans and vacation programs, that are customarily provided to other employees, to the extent he is eligible under the terms and conditions of such arrangements. Mr. Stice also is entitled to receive the following grants of Chesapeake restricted stock, provided he remains employed on the applicable grant date: (a) at least $1,250,000 worth of restricted stock, granted no later than January 31, 2011 (the “2011 Grant”), and (b) at least $1,750,000 worth of restricted stock, granted no later than January 31, 2012.
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Agreements with David C. Shiels and Robert S. Purgason
Messrs. Shiels and Purgason employment agreements are effective January 4, 2010 and December 1, 2009, respectively. The employment agreements each have a five-year term. Mr. Shiels serves as our general partner’s Chief Financial Officer, and Mr. Purgason serves as our general partner’s Chief Operating Officer.
The agreements provide Messrs. Shiels and Purgason with an annual base salary for 2010 of $300,000 and $350,000, respectively, which increased to $325,000 and $375,000, respectively, for 2011, and will increase to $350,000 and $400,000, respectively, effective January 31, 2012. Messrs. Shiels and Purgason each received a signing bonus of $100,000 and $125,000, respectively, that was paid three months following the effective dates of their respective agreements. Additionally, the agreements specify target annual bonuses for Messrs. Shiels and Purgason in the following amounts, payable in cash: (i) $100,000 and $300,000, respectively, which were paid in January 2011, (ii) $125,000 and $325,000, respectively, payable not later than January 31, 2012, and (iii) $150,000 and $350,000, respectively, payable not later than January 31, 2013, provided Messrs. Shiels and Purgason remain employed on the bonus dates. Payment of any bonus compensation is not guaranteed and remains within the discretion of Chesapeake Midstream Management L.L.C., with approval of our general partner’s board. Additionally, discretionary bonuses above the target bonus amounts may be made, in cash or stock, based on each executive’s annual performance review.
Messrs. Shiels and Purgason are also entitled to participate in the employee benefit plans and arrangements, such as retirement and health plans and vacation programs, that are customarily provided to other employees, to the extent eligible under the terms and conditions of such arrangements. They are also each entitled to receive (i) a relocation allowance of up to $50,000, payable within 30 days of relocation, provided relocation occurs within six months of the effective date of the agreement (18 months in the case of Mr. Shiels) and subject to a pro rata repayment obligation in the event of a voluntary termination during the first twelve months of the employment term (first 18 months of the employment term, in the case of Mr. Shiels), and reasonable temporary housing costs for up to 90 days, and (ii) reimbursement of the actual cost of health insurance premiums incurred for COBRA coverage until Messrs. Shiels and Purgason qualify for health coverage by reason of their employment. Until the time Mr. Shiels relocates to the Oklahoma City area or, if earlier, the 18 month anniversary of the effective date of his agreement, Mr. Shiels is also entitled to a monthly commuting allowance of $1,500.
The agreements further provide that Messrs. Shiels and Purgason each be awarded a percentage interest in a management incentive cash bonus pool, which is based on our long-term performance. These awards have been granted pursuant to Chesapeake Midstream Management, L.L.C.’s management incentive compensation plan, described below. Messrs. Shiels and Purgason may also be granted equity-based awards under our LTIP, described below, that will be subject to certain service and/or performance-based vesting requirements.
No amendments to the employment agreement with Messrs. Shiels and Purgason that would increase the compensation expenses reimbursable under the employee secondment agreement or adversely affect the protections afforded to us under the agreement may be made without the consent of the disinterested directors and the special committee of our general partner’s board of directors.
Management Incentive Compensation Plan
Chesapeake Midstream Management, L.L.C. has adopted the MICP which provides incentive compensation awards comprised of two components to key members of management who have been designated as participants by our general partner.
The first component of the award is an annual cash bonus based on “excess” cash distributions made by us each fiscal year above a target amount each year during a five-year period (the “Excess Return Component”). A participant’s Excess Return Component will generally be calculated by multiplying the “excess” distribution amount for an applicable year (or the amount of distributions that were made over “target” for that year) by the participant’s participation percentage assigned to him at the time of grant, by the annual payment percentage that is also assigned to the officer at the time of the grant. The Excess Return Component determined to be payable to a participant with respect to a specified fiscal year (if any) is paid pro-rata that year and in each of the years then remaining in the five-year period, provided the participant continues to be employed by us or an affiliate until the payment date.
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The second component is based on an increase in value of our common units at the end of the five-year period and is paid at the end of the five-year period (the “Equity Uplift Component”), unless a change of control occurs prior to that five-year period, at which time the award would be paid upon that change of control. This component of the MICP is calculated by multiplying the “equity uplift value,” if any, by the participants “equity uplift value percentage.” The “equity uplift value” is defined as the excess of the value of our units on the payment date over the value of our units on our IPO date (which was $21.00), multiplied by the number of our outstanding units on the payment date (which is a number that is undeterminable at the time of this filing). Each participant’s “equity uplift value percentage” is assigned pursuant to an award agreement. Awards that may become due under the MICP are paid to the participant over a five-year period.
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 the “Potential Payments Upon Termination or Change of Control” below.
The MICP is administered by the compensation committee of the board of directors of our general partner, which also has the authority to amend and terminate the MICP at any time, subject to certain limitations with respect to Excess Return payments that are based on fiscal years that have already lapsed at such time and Equity Uplift payments based on their accrued value at such time.
Long-Term Incentive Plan
General
Our general partner has adopted the Chesapeake Midstream LTIP, for employees, consultants and directors of our general partner and its affiliates, including Chesapeake, who perform services for us. The summary of the LTIP contained herein does not purport to be complete and is qualified in its entirety by reference to the LTIP. The LTIP provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights with respect to phantom units and other unit-based awards. Subject to adjustment for certain events, an aggregate of 3,500,000 common units may be delivered pursuant to awards under the LTIP. Units that are cancelled or forfeited are available for delivery pursuant to other awards. Units that are withheld to satisfy our general partner’s tax withholding obligations or payment of an award’s exercise price are not available for future 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 its ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees.
Unit Awards
Our general partner granted 2,381 units to each of Messrs. Daberko and Frederickson and Ms. Kelly in connection with their initial appointment to the board. The units had an aggregate grant date value to each director of approximately $50,000.
Restricted Units and Phantom Units
A restricted unit is a common unit that is subject to forfeiture. 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. 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. In addition, the restricted units and phantom units vest automatically upon a change of control of us or our general partner. Upon the vesting of phantom units, an amount of notional units equal to the taxes payable on the vesting of the phantom units is deducted from the number of phantom units vested and an amount of common units, or cash, equal to the remaining notional units is delivered to the grantee.
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Distributions made by us with respect to awards of phantom units may, in our general partner’s discretion, 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 receive remuneration for the units delivered with respect to these awards.
Our general partner intends 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 and will have 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 death, disability or change of control of our general partner). On January 3, 2011, each of Messrs. Daberko and Frederickson and Ms. Kelly were awarded 1,748 phantom units and, in recognition of successful management of the partnership’s IPO, Messrs. Stice, Shiels and Purgason were awarded 7,500, 5,000 and 5,000 phantom units, respectively, which will vest one quarter on each of the first, second, third and fourth anniversary of the grant date (with vesting to be accelerated upon death, disability or change of control of our general partner).
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, an 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 directly from us or 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. 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. 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.
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Amendment or Termination of Long-Term Incentive Plan
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. 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 Code unless otherwise determined by our general partner.
Summary Compensation Table
The following table summarizes the compensation amounts for each of the named executive officers for the fiscal year ended December 31, 2010.
| Name and Principal Position |
Year | Salary ($)(1) |
Bonus ($)(2) |
Stock Awards ($)(3) |
Option Awards ($)(3) |
Non-Equity Incentive Plan Compen- sation ($)(4) |
Change in Pension Value and Nonqualified Deferred Compen- sation Earnings ($)(5) |
All Other Compen- sation ($)(6) |
Total ($) |
|||||||||||||||||||||||||||
| J. Mike Stice(7) |
2010 | $ | 249,308 | $ | 188,000 | $ | 637,400 | $ | — | $ | — | $ | — | $ | 13,263 | $ | 1,087,971 | |||||||||||||||||||
| David C. Shiels |
2010 | 300,337 | 225,500 | — | — | — | — | 46,451 | 572,288 | |||||||||||||||||||||||||||
| Robert S. Purgason |
2010 | 356,106 | 301,300 | — | — | — | — | 81,776 | 739,182 | |||||||||||||||||||||||||||
| (1) | The amounts in this column reflect the base salary compensation earned by our named executive officers for the fiscal year ended December 31, 2010. |
| (2) | The amounts in this column reflect bonuses earned by the named executive officers in the fiscal year ended December 31, 2010. For each of the named executive officers, the bonus amounts include bonuses provided for in their respective employment agreements and routine holiday bonuses. For Mr. Shiels, the amount includes a signing bonus of $125,000 paid three months following the effective date of his employment. |
| (3) | The amount shown in these columns reflect the aggregate grant date fair value of Chesapeake restricted stock awards granted to Mr. Stice, determined in accordance with FASB ASC Topic 718. 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. Refer to the Grants of Plan-Based Awards Table for 2010 for additional information regarding restricted stock awards made to Mr. Stice in the year ended December 31, 2010. No stock options, restricted unit awards or phantom unit awards were granted by our general partner in the year ended December 31, 2010. More information about the named executive officers’ outstanding restricted stock and stock options as of December 31, 2010 is provided in the Outstanding Equity Awards at 2010 Fiscal Year End Table. Unvested restricted stock does not accrue dividends. |
| (4) | No amounts were earned by the named executive officers in 2010 under any non-equity incentive plan. |
| (5) | Our named executive officers do not participate in a pension plan. In addition, Chesapeake’s nonqualified deferred compensation plans do not provide for above-market or preferential earnings. See nonqualified Deferred Compensation for 2010 below for more information regarding Chesapeake’s nonqualified deferred compensation plan. |
| (6) | The amounts in this column reflect all other compensation earned by the named executive officers for the fiscal year ended December 31, 2010. The other compensation provided to the named executive officers consists of matching contributions under Chesapeake’s retirement plans, supplemental life insurance premiums, financial advisory services, tickets to certain sporting events and temporary housing benefits. In addition, this column reflects a relocation benefit of $46,400 provided to Mr. Purgason and a commuting allowance provided to Mr. Shiels in the year ended December 31, 2010. |
| (7) | The amounts in this row reflect compensation of Mr. Stice for his time spent providing services to the Partnership in the year ended December 31, 2010, which was approximately 50 percent of his time. |
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Grants of Plan-Based Awards in 2010
The following table sets forth information concerning Chesapeake restricted stock granted during 2010 to Mr. Stice as well as incentive awards made to Messrs. Shiels and Purgason under the MICP. The chart below does not take into account that under our employee secondment agreement and, in the case of Mr. Stice, the shared services agreement, we may only be allocated a portion of the expense related to these awards.
| Name |
Grant Date | Approval Date(1) | Estimated Future Payout Under Non- Equity Incentive Plan Awards - Target ($)(2) |
Estimated Future Payouts Under Equity Incentive Plan Awards ($) |
All Other Stock Awards: Number of Shares of Stock or Units (#)(3) |
Grant Date Fair Value of Stock Awards ($)(4) |
||||||||||||||||||
| J. Mike Stice |
January 4, 2010 | December 17, 2009 | $ | — | $ | — | 12,500 | $ | 351,125 | |||||||||||||||
| July 1, 2010 | June 10, 2010 | — | — | 13,750 | 286,275 | |||||||||||||||||||
| 26,250 | $ | 637,400 | ||||||||||||||||||||||
| David C. Shiels |
— | — | 62,169(5) | — | — | $ | — | |||||||||||||||||
| — | — | 1,153,571(6) | — | — | $ | — | ||||||||||||||||||
| Robert S. Purgason |
— | — | 124,337(5) | — | — | $ | — | |||||||||||||||||
| — | — | 2,307,142(6) | — | — | $ | — | ||||||||||||||||||
| (1) | The compensation committee of Chesapeake’s board of directors approved the Chesapeake restricted stock awards to Mr. Stice at regularly scheduled meetings. The committee’s approval on December 17, 2009 provided for the restricted stock grant date to be the first trading day of January 2010. Its approval on June 10, 2010 provided for the restricted stock grant date to be the first trading day of July 2010. |
| (2) | Reflects estimated future payouts to Messrs. Shiels and Purgason, with regard to awards granted under the MICP in the fiscal year ended December 31, 2010, upon the 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 on January 4, 2010 and July 1, 2010 vest ratably over four years from the grant date of the award. No dividends are accrued or paid on restricted stock awards until vested. |
| (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 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. |
| (5) | The Excess Return Component is determined following the conclusion of each fiscal year in a five-year period beginning with 2010, 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. Shiels and Purgason 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. Shiels and Purgason 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. For more information regarding the MICP, please see the narrative disclosure to this table. |
| (6) | 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. Shiels and Purgason if the award determination date was December 31, 2010. 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. Shiels and Purgason’s percentage interest in any appreciation of such price over the Partnership’s IPO price. For more information regarding the MICP, please see the narrative disclosure to this table. |
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Narrative Disclosure for Grants of Plan-Based Awards in 2010
Restricted Stock
As discussed under “Compensation Discussion and Analysis” above, equity compensation in the form of Chesapeake restricted stock for the named executive officers, is reviewed on a semi-annual basis, in June and December. With respect to the June compensation review, restricted stock is awarded to the named executive officers effective the first trading day of July based on amounts approved by Chesapeake’s compensation committee at its December meeting. With respect to the December compensation review, restricted stock is awarded to the named executive officers effective the first trading day of January based on amounts approved by Chesapeake’s compensation committee at its December meeting. Mr. Stice was the only named executive officer to receive restricted stock during 2010. No stock options, restricted unit awards or phantom unit awards were granted in 2010.
MICP Awards
As reflected in the Grants of Plan-Based Awards table and discussed under “Compensation Discussion and Analysis” above, we made grants to Messrs. Shiels and Purgason under the MICP in 2010. Each grant is made up of two components, the Excess Return Component and the Equity Uplift Component. Because the two components of the MICP awards are measured and paid at different times and based on different metrics we have disclosed them as two separate grants in the table above to provide a clearer understanding of how these awards function.
The Excess Return Component is calculated at the end of each year based on certain factors related to our performance for that year. The MICP is a multi-year award, and as such it provides that this process is repeated each year for five years. At the end of each of those years the named executive officer has either earned a payment for that year or not. If a payment has been earned under the Excess Return Component, it will be paid to the named executive officer in lump-sum cash payments pro-rata each year for the remainder of the five year period. For example, a payment earned in 2010 would be paid out 20% per year immediately following the end of each year between 2010 and 2014 but a payment earned for 2014 would be paid in one lump-sum payment following the end of that fiscal year (because the award was earned for the last year in the five year period). The Excess Return Component is calculated by multiplying the “excess” distribution amount for an applicable year (the amount of distributions that were made over “target” for that year) by the participant’s participation percentage (.125% for Mr. Shiels and .25% for Mr. Purgason). The amount disclosed in the chart above as the “target” represents the aggregate amount that Messrs. Shiels and Purgason would receive based on the assumption that we maintain our minimum quarterly distribution to unitholders over the term of the award. In the event that we increase our quarterly distribution rate, the amounts payable to Messrs. Shiels and Purgason would also increase.
The Equity Uplift Component is measured and paid at the end of the five year period based on the increase in value of our common units over that five year period. This component is calculated by multiplying the “equity uplift value” (the increase in our market capitalization over the course of the five years following our IPO) by the participant’s “equity uplift value percentage” (.125% for Mr. Shiels and .25% for Mr. Purgason). Because we cannot know what the “equity uplift value” will be until the five year anniversary of our IPO, the amount disclosed in the chart above represents a “representative” estimate of the future payment to Messrs. Shiels and Purgason for the Equity Uplift Component assuming that the award was paid based upon the Partnership’s common unit price as of December 31, 2010.
Please see our discussion of the MICP under “Compensation Discussion and Analysis” above for more information on the MICP generally. Also, please see “Potential Payments Upon Termination or Change of Control” below for information about potential payments on a separation from service of one of our named executive officers or a change of control.
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Outstanding Equity Awards at Fiscal Year-End 2010
The following table reflects outstanding equity awards as of December 31, 2010 for each of the named executives, including both Chesapeake and Partnership awards granted in connection with their service to the Partnership.
| Option Awards | Stock Awards | |||||||||||||||||||||||||||||||||||
| Number of Securities Underlying Unexercised Options (#) |
Number of Securities Underlying Unexercised Options (#) |
Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) |
Option Exercise Price ($) |
Option Expiration Date |
Grant Date of Shares or Units of Stock That Have Not Vested |
Number of Shares or Units of Stock That Have Not Vested (#)(1) |
Market Value of Shares or Units of Stock That Have Not Vested ($)(2) |
Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) |
Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) |
|||||||||||||||||||||||||||
| J. Mike Stice |
— | — | — | — | — | January 4, 2010 | 12,500 | 328,875 | — | — | ||||||||||||||||||||||||||
| — | — | — | — | — | July 1, 2010 | 13,750 | 356,263 | — | — | |||||||||||||||||||||||||||
| David C. Shiels |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||
| Robert S. Purgason |
— | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||
| (1) | By their terms, the Chesapeake restricted stock awards granted on January 4, 2010 and July 1, 2010 vest ratably over four years from the grant date of the award. |
| (2) | The value shown is based on the closing price of Chesapeake’s common stock on December 31, 2010 of $25.91 per share. |
Option Exercises and Stock Vested in 2010
None of our named executive officers exercised any stock options during the fiscal year ended December 31, 2010, nor did any vesting occur with respect to a stock award held by any named executive officer that was granted in connection with their service to the Partnership.
Non-Qualified Deferred Compensation for 2010
The named executive officers are permitted to participate in the Chesapeake Amended and Restated Deferred Compensation Plan (the “DCP”), a nonqualified deferred compensation plan. The DCP allows certain employees to voluntarily defer receipt of a portion of their salary and/or their annual bonus payments. Pursuant to the terms of the employee secondment agreement and, in the case of Mr. Stice, the shared services agreement, a portion of the expense related to these plans is allocated to us by Chesapeake. None of the named executive officers participated in the DCP in the year ended December 31, 2010. For additional discussion of the DCP, please see “Executive Compensation—Nonqualified Deferred Compensation Table for 2010” of Chesapeake’s proxy statement for its annual meeting of shareholders, which is expected to be filed no later than May 2, 2011.
Potential Payments Upon Termination or Change of Control
As discussed under “Compensation Discussion and Analysis” above, we provide our named executive officers with certain compensation guarantees in the event of a termination without cause, change of control, retirement, incapacity or death. The termination arrangements with our named executive officers are contained in their respective employment agreements and the incentive plans in which our named executive officers participate and the DCP. Below is a discussion of these arrangements.
J. Mike Stice. Mr. Stice’s employment agreement provides for certain change of control and termination benefits in the event of a change of control or a termination of Mr. Stice’s employment under certain circumstances. If a change of control (as defined below) occurs during the term of the agreement, Mr. Stice will receive a lump sum payment no later than the 75th day following the calendar year in which the change of control occurred, equal to 200% 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. However, the payment will be subject to interest if not paid within 30 days of the change of control.
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Upon written notice, Mr. Stice’s employment may be terminated by either party to his agreement for any reason. Generally, upon any termination, Mr. Stice will be entitled to receive only accrued but unpaid compensation, such as vacation amounts, and any amounts due to him pursuant to the terms of an employee benefit plan. In the event Mr. Stice’s employment is terminated without cause (as defined below), he will also be entitled to the following: (i) a lump sum payment equal to one year’s worth of base salary, (ii) all restricted stock granted under the agreement will vest in full upon the termination, and (iii) if the termination occurs before January 31, 2011, and Mr. Stice has not yet received the 2011 Grant, a payment, in either cash or Chesapeake stock, equal to $1,250,000.
In the event of Mr. Stice’s retirement following at least five years of service and the attainment of at least age 55, Mr. Stice will receive accelerated vesting, in whole or in part, of (i) his supplemental matching contributions under the Chesapeake 401(k) Make-Up Plan (which is more thoroughly described in Chesapeake’s proxy statement for its annual meeting of shareholders, which is expected to be filed no later than May 2, 2011), and (ii) all unvested equity compensation. If Mr. Stice dies, his beneficiary or estate will be entitled to continue receiving his base salary for a period of one year following his date of death and all restricted Chesapeake stock granted under the agreement will vest in full, subject to the execution (and nonrevocation) of the severance and release agreement described below.
If Mr. Stice is terminated due to a disability (as defined below), he will continue to receive his base salary and other compensation for a period of 180 days following the termination date, reduced by any benefits payable under any employer-sponsored disability plan. In addition, if the termination occurs before January 31, 2011, and Mr. Stice has not yet received the 2011 Grant, he will receive a payment, in either cash or Chesapeake stock, equal to $1,250,000.
All severance payments due upon Mr. Stice’s termination without cause or due to his disability will be made within 60 days of the termination date, unless Mr. Stice constitutes a “specified employee” within the meaning of Section 409A of the Code, in which case payments subject to Section 409A of the Code will be delayed for six months following the termination date. All severance payments and benefits are contingent on Mr. Stice (or, in the event of his death, his beneficiary or the administrator of his estate) executing (and not revoking) a severance and release agreement within 45 days of the termination, and complying with the restrictive covenants described below.
Mr. Stice’s agreement contains certain confidentiality, noncompete, and nonsolicitation covenants. Specifically, Mr. Stice has agreed not to disclose any confidential information during the term of his employment and for three years following his termination. In addition, Mr. Stice has agreed to a noncompete covenant for six months following his termination and not to solicit customers or employees for a period of one year following his termination.
A “change of control” is generally defined in Mr. Stice’s employment agreement as the occurrence of one of the following: (a) the acquisition by a group of 30% 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 6, 2008, cease to constitute at least a majority of that board; (c) the consummation of a reorganization, merger, consolidation or sale of all or substantially all of the assets of Chesapeake; or (d) the approval by the Chesapeake shareholders of a complete liquidation or dissolution. “Cause” is defined in the agreement as Mr. Stice’s breach of his agreement, his neglect of duties, his misappropriation, fraudulent conduct or dishonesty with respect to company business, or his personal misconduct involving moral turpitude; a termination without cause includes such events as Chesapeake’s elimination of Mr. Stice’s position, a material reduction in duties and/or reassignment of Mr. Stice to a new position of less authority, or a material reduction to his compensation. Mr. Stice will be considered incapacitated, or disabled, under his employment agreement if he suffers from a physical or mental condition which, in the reasonable judgment of Chesapeake’s management, prevents Mr. Stice from performing his duties for a period of at least three consecutive months.
Mr. Stice’s termination and change of control benefits are provided to him in connection with the services that he provides to Chesapeake and the Partnership is not required to reimburse Chesapeake for any such benefits.
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David C. Shiels and Robert S. Purgason. Mr. Shiels’ and Mr. Purgason’s employment agreements provide for certain termination benefits in the event of a termination of Mr. Shiels or Mr. Purgason under certain specified circumstances. Upon written notice, Mr. Shiels’ or Mr. Purgason’s employment may be terminated by either party to the agreement for any reason. Generally, upon any termination, Messrs. Shiels and Purgason will be entitled to receive only accrued but unpaid compensation, such as base salary and vacation amounts, and any amounts due to them pursuant to the terms of an employee benefit plan.
In the event Mr. Shiels’ or Mr. Purgason’s employment is terminated without cause (similarly defined as the term “cause” in Mr. Stice’s agreement described above), he will also be entitled to a lump sum payment equal to one year’s worth of base salary (26 weeks’ worth of base salary, in the case of Mr. Shiels). If the termination without cause occurs within two years following the occurrence of a change of control (as defined in the employment agreement), Messrs. Shiels and Purgason are also entitled to receive, in addition to the base salary amounts described in the preceding sentence, an amount equal to the actual bonuses paid to them during the 12 calendar months preceding the change of control.
If either Mr. Shiels or Mr. Purgason is terminated due to a disability (similarly defined as the terms “incapacitated” and “disabled” in Mr. Stice’s agreement described above), he will be entitled to a lump sum payment equal to 26 weeks’ worth of base salary, reduced by any benefits payable under any employer-sponsored disability plan. If either Mr. Shiels or Mr. Purgason dies, his beneficiary or estate will be entitled to receive a lump sum payment equal to 52 weeks’ worth of his base salary.
All payments due upon the termination of Messrs. Shiels and Purgason will be made within 30 days of the termination date (90 days, in the case of death), unless the executive constitutes a “specified employee” within the meaning of Section 409A of the Code, in which case payments subject to Section 409A will be delayed until the earlier of the executive’s death or six months following the termination date. Such payments are contingent on the Executive (or, in the event of his death, his beneficiary or the administrator of his estate) executing (and not revoking) a severance and release agreement within 30 days of the termination (90 days, in the case of death), and complying with the restrictive covenants described below.
The employment agreements with Messrs. Shiels and Purgason contain certain confidentiality, noncompete, and nonsolicitation covenants. Specifically, Messrs. Shiels and Purgason have agreed not to disclose any confidential information at any time either during or following the term of their employment. In addition, Messrs. Shiels and Purgason have agreed to a noncompete covenant for one year (26 weeks, in the case of Mr. Shiels) following termination and not to solicit customers or employees for a period of one year following termination. Termination of either Mr. Shiels’ or Mr. Purgason’s employment due to the violation of one of these covenants would constitute a termination for cause.
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Messrs. Shiels and Purgason are participants under the MICP. Under the MICP, unless waived by the compensation committee of the board of directors of our general partner, in its discretion, if a participant’s employment terminates for any reason prior to a payment date, other than due to his or her death, disability, involuntary termination by the employer other than for “cause” (as defined in the MICP), or by the participant for a “good reason” (as defined in the MICP) (such events collectively being a “Qualified Termination”), the participant’s award will be automatically forfeited on his or her termination of employment. If, however, a participant’s termination of employment is a Qualified Termination, the participant will be paid (i) on his or her termination the remaining amount of any unpaid annual installments attributable to the participant’s Excess Return Component for the fiscal years that have been completed as of the participant’s termination date, and (ii) at the end of the five-year period, a prorata portion of the participant’s Equity Uplift Component (if any) during such five-year period. Awards will be paid in cash, unless 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 installments attributable to fiscal years then completed and (ii) with respect to the Equity Uplift Component, an amount based on the increase in the value of our common units over the beginning value of our common units. Participants who have incurred a Qualified Termination prior to the change of control will receive, with respect to the Equity Uplift Component, a prorata portion of the amount that otherwise would have been payable to them had their 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, 2010.
| David C. Shiels - Executive Benefits and Payments Upon Separation |
Termination without Cause |
Change of
Control |
Retirement | Incapacity of Executive |
Death
of Executive |
|||||||||||||||
| Compensation: |
||||||||||||||||||||
| Cash Severance |
$ | 156,250 | $ | 206,750 | $ | — | $ | 156,250 | $ | 312,500 | ||||||||||
| Acceleration of Equity Compensation: |
||||||||||||||||||||
| Restricted Unit/Stock Awards |
— | — | — | — | — | |||||||||||||||
| Deferred Comp Plan Matching |
— | — | — | — | — | |||||||||||||||
| Acceleration of Non-Equity Incentive Compensation: |
||||||||||||||||||||
| Management Incentive Compensation Plan(1) |
230,714 | 1,153,571 | — | 230,714 | 230,714 | |||||||||||||||
| Benefits and Perquisites: |
||||||||||||||||||||
| Accrued Vacation Pay |
263 | 263 | 263 | 263 | 263 | |||||||||||||||
| Total |
$ | 387,227 | $ | 1,360,584 | $ | 263 | $ | 387,227 | $ | 543,477 | ||||||||||
| (1) | Estimates amounts that would have been payable under the Equity Uplift Component on December 31, 2010 based upon the assumption that the Partnership’s common units would be valued at $27.68, the average closing price for the units over a trailing 30-day period. |
| Robert S. Purgason - Executive Benefits and Payments Upon Separation |
Termination without Cause |
Change of
Control |
Retirement | Incapacity of Executive |
Death
of Executive |
|||||||||||||||
| Compensation: |
||||||||||||||||||||
| Cash Severance |
$ | 362,500 | $ | 513,500 | $ | — | $ | 181,250 | $ | 362,500 | ||||||||||
| Acceleration of Equity Compensation: |
||||||||||||||||||||
| Restricted Unit/Stock Awards |
— | — | — | — | — | |||||||||||||||
| Deferred Comp Plan Matching |
— | — | — | — | — | |||||||||||||||
| Acceleration of Non-Equity Incentive Compensation: |
||||||||||||||||||||
| Management Incentive Compensation Plan(1) |
461,428 | 2,307,142 | — | 461,428 | 461,428 | |||||||||||||||
| Benefits and Perquisites: |
||||||||||||||||||||
| Accrued Vacation Pay |
25,593 | 25,593 | 25,593 | 25,593 | 25,593 | |||||||||||||||
| Total |
$ | 849,521 | $ | 2,846,235 | $ | 25,593 | $ | 668,271 | $ | 849,521 | ||||||||||
| (1) | Estimated amounts that would have been payable under the Equity Uplift Component on December 31, 2010, based upon the assumption that the Partnership’s common units would be valued at $27.68, the average closing price for the units over a trailing 30-day period. |
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Compensation of Directors
Officers or employees of Chesapeake and GIP who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Our independent directors receive compensation for attending meetings of our general partner’s board of directors. Such compensation consists of an annual retainer of $60,000 for each board member, except for the chairman of the board of directors who receives $70,000, a fee of $2,500 for each board meeting attended in person and a fee of $1,000 for each telephonic board meeting attended. 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 $50,000, 25% of which will be vested on the grant date and 75% of which will be phantom units that vest one-third on each of the first, second and third anniversary of the date of grant (with vesting to be accelerated upon death, disability or a change of control of our general partner). In addition, each director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director is fully indemnified by us, pursuant to individual indemnification agreements and our partnership agreement, for actions associated with being a director to the fullest extent permitted under Delaware law.
The following table sets forth the compensation earned by the directors of our general partner in 2010:
| Name |
Fees Earned or Paid in Cash ($) |
Stock Awards
($)(1) |
Option Awards ($) |
All
Other Compensation ($) |
Total ($) |
|||||||||||||||
| David A. Daberko |
$ | 35,834 | $ | 50,001 | $ | — | $ | — | $ | 85,835 | ||||||||||
| Aubrey K. McClendon |
— | — | — | — | — | |||||||||||||||
| Marcus C. Rowland |
— | — | — | — | — | |||||||||||||||
| Matthew C. Harris |
— | — | — | — | — | |||||||||||||||
| William A. Woodburn. |
— | — | — | — | — | |||||||||||||||
| Philip A. Frederickson |
35,000 | 50,001 | — | — | 85,001 | |||||||||||||||
| Suedeen G. Kelly |
35,000 | 50,001 | — | — | 85,001 | |||||||||||||||
| (1) | Reflects the aggregate grant date fair value of 2010 unit awards computed in accordance with FASB ASC Topic 718. Messrs. Daberko and Frederickson and Ms. Kelly were each awarded 2,381 common units upon their appointment as directors of our general partner. As of December 31, 2010, there were no outstanding stock awards or option awards. |
Compensation Committee Interlocks and Insider Participation
In 2010, Ms. Kelly and Messrs. Harris and Rowland served on the compensation committee of our general partner’s board of directors. Mr. Rowland was also an executive officer of Chesapeake during 2010 and retired from that position in October 2010. Mr. Rowland did not receive compensation in 2010 for his service as a director of our general partner. Please see “Item 13. Certain Relationships and Related Transactions, and Director Independence” for more information about relationships among us, our general partner and Chesapeake.
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.”
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| ITEM 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The following table sets forth the beneficial ownership of our units that, unless otherwise noted, as of March 7, 2011, are held by:
| • | each member of our general partner’s board of directors; |
| • | each named executive officer of our general partner; |
| • | all directors and officers of our general partner as a group; and |
| • | each person or group of persons known by us to be a beneficial owner of 5% or more of the then outstanding units. |
| Name and address of beneficial owner(1) |
Common units beneficially owned |
Percentage of common units beneficially owned(2) |
Subordinated units beneficially owned |
Percentage of subordinated units beneficially owned(2) |
Percentage of total common and subordinated units beneficially owned(2) |
|||||||||||||||
| Chesapeake Energy Corporation(3) |
23,913,061 | 34.6 | % | 34,538,061 | 50.0 | % | 42.3 | % | ||||||||||||
| GIP(5) |
20,725,561 | 30.0 | % | 34,538,061 | 50.0 | % | 40.0 | % | ||||||||||||
| ClearBridge Advisors, LLC(4) |
3,600,000 | 5.2 | % | — | — | 2.6 | % | |||||||||||||
| J. Mike Stice |
12,334 | * | % | — | — | * | % | |||||||||||||
| Robert S. Purgason |
14,200 | * | % | — | — | * | % | |||||||||||||
| David C. Shiels |
— | * | % | — | — | * | % | |||||||||||||
| Matthew C. Harris(5) |
— | * | % | — | — | * | % | |||||||||||||
| Aubrey K. McClendon(3)(6) |
53,700 | * | % | — | — | * | % | |||||||||||||
| Marcus C. Rowland |
15,200 | * | % | — | — | * | % | |||||||||||||
| William A. Woodburn(5) |
— | * | % | — | — | * | % | |||||||||||||
| David A. Daberko |
7,518 | * | % | — | — | * | % | |||||||||||||
| Philip L. Frederickson |
12,318 | * | % | — | — | * | % | |||||||||||||
| Suedeen G. Kelly |
2,818 | * | % | — | — | * | % | |||||||||||||
| All directors and executive officers as a group (ten persons) |
118,088 | * | % | — | — | * | % | |||||||||||||
| * | Less than 1.0% |
| (1) | Unless otherwise indicated, the address for all beneficial owners in this table is 900 N.W. 63rd Street, Oklahoma City, Oklahoma 73118. |
| (2) | Based on 69,084,576 common units and 69,076,122 subordinated units outstanding. |
| (3) | This information is as of December 31, 2010, as reported in a Schedule 13G filed by Chesapeake, the ultimate parent company of Chesapeake Midstream Holdings, who is the owner of 50% of the membership interests of Chesapeake Midstream Ventures and the owner of common units and subordinated units. Chesapeake may be deemed to beneficially own the interests held directly or indirectly by Chesapeake Midstream Holdings. |
| (4) | This information is as of December 31, 2010, as reported in a Schedule 13G filed by ClearBridge Advisors, LLC, the parent company of ClearBridge Energy MLP Fund, Inc., on February 11, 2011. The Schedule 13G reports (i) sole power to vote or direct the vote of 3,600,000 common units and (ii) sole power to dispose or direct the disposition of 3,600,000 common units. ClearBridge Advisors, LLC may be deemed to beneficially own the interests held directly or indirectly by ClearBridge Energy MLP Fund, Inc. |
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| (5) | This information is as of December 31, 2010, as reported in a Schedule 13G filed jointly by Global Infrastructure Investors, Limited (“Global Infrastructure Investors”), Global Infrastructure Management, LLC (“Global Infrastructure Management”), Global Infrastructure GP, L.P., GIP-A Holding (CHK), L.P. (“GIP-A”), GIP-B Holding (CHK), L.P. (“GIP-B”) and GIP-C Holding (CHK), L.P. (“GIP-C”) on February 11, 2011. Global Infrastructure Investors is the sole general partner of Global Infrastructure GP, L.P., which is the sole general partner of the limited partnerships (the “GIP Partnerships”) that directly or indirectly own the general partners of each of GIP-A, GIP-B and GIP-C. Global Infrastructure Management manages the GIP Partnerships. GIP-A, GIP-B and GIP-C hold the following interests in us: |
| • | GIP-A owns 7,287,810 common units, 12,144,753 subordinated units and a 17.5816953% membership interest in Chesapeake Midstream Ventures; |
| • | GIP-B owns 2,826,853 common units, 4,710,802 subordinated units and a 6.8197258% membership interest in Chesapeake Midstream Ventures; and |
| • | GIP-C owns 10,610,898 common units, 17,682,506 subordinated units and a 25.5985789% membership interest in Chesapeake Midstream Ventures. |
Matthew C. Harris and William A. Woodburn, two of the directors of our general partner, as members of Global Infrastructure Management’s internal committees, are entitled to vote on decisions to vote, or to direct to vote, and to dispose, or to direct the disposition of, the common units and subordinated units held by GIP-A, GIP-B and GIP-C but cannot individually or together control the outcome of such decisions. Global Infrastructure Investors, Matthew C. Harris and William A. Woodburn disclaim beneficial ownership of the common units and subordinated units held by GIP-A, GIP-B and GIP-C in excess of their respective pecuniary interest in such units. Global Infrastructure Investors and Global Infrastructure Management disclaim beneficial ownership of the common and subordinated units held by GIP-A, GIP-B and GIP-C.
| (6) | Includes 47,600 common units held by Mr. McClendon’s immediate family members sharing the same household. |
The following table sets forth the number of shares of common stock of Chesapeake that, as of March 7, 2011, are owned by each of the executive officers, directors and nominees to our general partner’s board of directors and all directors and executive officers of our general partner as a group.
| Name and address of beneficial owner(1) |
Shares of common stock owned directly or indirectly |
Shares underlying options exercisable within 60 days |
Total shares of common stock beneficially owned |
Percentage of total shares of common stock beneficially owned(2) |
||||||||||||
| J. Mike Stice |
14,940 | — | 14,940 | * | % | |||||||||||
| Robert S. Purgason |
237 | — | 237 | * | % | |||||||||||
| David C. Shiels |
173 | — | 173 | * | % | |||||||||||
| Matthew C. Harris |
— | — | — | * | % | |||||||||||
| Aubrey K. McClendon |
1,330,364 | — | 1,330,364 | * | % | |||||||||||
| Marcus C. Rowland |
208,842 | — | 208,842 | * | % | |||||||||||
| William A. Woodburn |
— | — | — | * | % | |||||||||||
| David A. Daberko |
— | — | — | * | % | |||||||||||
| Philip L. Frederickson |
— | — | — | * | % | |||||||||||
| Suedeen G. Kelly |
— | — | — | * | % | |||||||||||
| * | Less than 1.0% |
| (1) | The address for all beneficial owners in this table is 900 N.W. 63rd Street, Oklahoma City, Oklahoma 73118. |
| (2) | As of February 18, 2011, there were 657,634,451 shares of Chesapeake common stock issued and outstanding. |
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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, 2010. For more information regarding the LTIP, which did not require approval by our unitholders, please see “Item 11. Executive Compensation—Long-Term Incentive Plan.”
| Plan Category |
Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights |
Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights |
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(1)) | |||
| Equity compensation plans approved by security holders |
— | — | — | |||
| Equity compensation plans not approved by security holders(1) |
— | — | 3,492,857 |
| (1) | The board of directors of our general partner adopted the LTIP in connection with our IPO. |
| ITEM 13. | Certain Relationships and Related Transactions, and Director Independence |
Chesapeake owns an aggregate of 23,913,061 common units and 34,538,061 subordinated units, representing an aggregate 41.5% limited partner interest in us, and GIP owns an aggregate of 20,725,561 common units and 34,538,061 subordinated units, representing an aggregate 39.20% limited partner interest in us. In addition, Chesapeake and GIP, through their joint ownership of Chesapeake Midstream Ventures, each indirectly own 50% of our general partner, which owns a 2.0% general partner interest in us and all of our incentive distribution rights.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and any liquidation of Chesapeake Midstream Partners, L.P. These distributions and payments were determined by and among affiliated entities.
Formation Stage
| The aggregate consideration received by Chesapeake and GIP for the contribution of the assets and liabilities to us in connection with our IPO in 2010 |
• 47,826,122 common units; • 69,076,122 subordinated units; • a 2.0% general partner interest; • our incentive distribution rights; and • GIP’s receipt the net proceeds from the exercise of the underwriters’ option to purchase additional common units in connection with our initial public offering in 2010. |
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Operational Stage
| Distributions of available cash to our general partner and its affiliates |
We generally make cash distributions 98.0% to our unitholders pro rata, including Chesapeake and GIP as the holders of an aggregate 47,638,622 common units and 69,076,122 subordinated units, and 2.0% to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0% 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% of the distributions above the highest target distribution level.
Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner receives an annual distribution of approximately $3.8 million on its general partner interest and Chesapeake and GIP receive an aggregate annual distribution of approximately $153.5 million on their common and subordinated units.
If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and to maintain its general partner interest.
| |
| Payments to our general partner and its affiliates |
Our general partner does not receive a management fee or other compensation for the management of our partnership. Prior to making distributions, we reimburse Chesapeake for its provision of certain general and administrative services and any additional services we may request from Chesapeake (including certain incremental costs and expenses we incur as a result of being a publicly traded partnership which are approximately $2.0 million per year), each pursuant to the services agreement; the costs and expenses of employees seconded to us pursuant to the employee secondment agreement; and certain costs and expenses incurred in connection with the services of Mr. Stice as the chief executive officer of our general partner pursuant to the shared services agreement. Other than the volumetric cap on general and administrative expenses included in the services agreement, our reimbursement obligations are uncapped. Please read “—Agreements with Affiliates—Services Agreement,” “—Employee Secondment Agreement” and “—Shared Services Agreement” below. In addition, we reimburse our general partner and its affiliates for all expenses they incur on our behalf. Under our partnership agreement, our general partner determines in good faith the amount of these expenses.
| |
| 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. | |
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Agreements with Affiliates
We have entered into the various documents and agreements with Chesapeake and certain of its affiliates, as described in more detail below. Substantially all of the commercial terms of these agreements were negotiated between Chesapeake and GIP in connection with their formation of the midstream joint venture Chesapeake Midstream Partners, L.L.C. In connection with our initial public offering in 2010, the commercial terms of these agreements were incorporated into amended agreements that were generally intended to provide us with substantially similar benefits and obligations of the private midstream joint venture.
Omnibus Agreement
We have entered into an omnibus agreement with Chesapeake Midstream Ventures and Chesapeake Midstream Holdings that will address the following matters:
| • | Chesapeake’s obligation to provide us with certain rights relating to certain future midstream business opportunities; and |
| • | our right to indemnification for certain liabilities and our obligation to indemnify Chesapeake Midstream Ventures and affiliated parties for certain liabilities. |
Business Opportunities. Pursuant to the omnibus agreement, Chesapeake Midstream Holdings provides us, or causes Chesapeake and its affiliates to provide us, with the opportunity to make offers with respect to three specified categories of transactions as described in more detail below: (i) proximate area opportunities, (ii) terminating third-party contract opportunities and (iii) monetization transaction opportunities. The consummation, if any, and timing of any such future transactions will depend upon, among other things, our ability to reach an agreement with the applicable Chesapeake entity and our ability to obtain financing on acceptable terms. Although we have certain rights with respect to the potential business opportunities described below, we are not under any contractual obligation to pursue any such transactions and Chesapeake is under no obligation to accept any offer made by us with respect to such opportunities.
Proximate Area Opportunities. Chesapeake Midstream Holdings is required to offer us the opportunity to make a first offer with respect to all potential investments in, opportunities to develop or acquisitions of any midstream energy projects (including well connections) within five miles of any of our Barnett or Mid-Continent acreage dedications that may from time to time become available to Chesapeake and its affiliates, other than those which were or will be subject to a certain agreed-upon dedication or similar arrangement, although Chesapeake will not be obligated to accept any offer we make. Our Barnett acreage dedication consists of portions of nine counties in northern Texas, including Johnson and Tarrant counties. Our Mid-Continent acreage dedication consists of portions Arkansas, Kansas, New Mexico, Oklahoma and Texas. We refer to the five mile areas outside of the acreage dedications as the “proximate areas”.
Upon our receipt of written notice of a proximate area opportunity, we have the right, exercisable within either ten days (in the case of individual well connections) or 30 days (in the case of all other proximate area opportunities), to make a first offer for us to pursue such opportunity. Such offer must include, to the extent reasonably practicable, reasonable detail regarding the terms upon which we would be willing to pursue such proximate area opportunity. Unless Chesapeake Midstream Holdings rejects our offer by written notice to us within 30 days of the delivery of our offer, our offer is be deemed to have been accepted by Chesapeake Midstream Holdings, and we have the right to pursue such proximate area opportunity on the terms set forth in our offer. In the event that we decline to make an offer or Chesapeake Midstream Holdings validly rejects our offer, Chesapeake will be free to pursue the proximate area opportunity on its own or in a transaction with an unaffiliated third party, provided that the terms and conditions of any such transaction cannot be more favorable in the aggregate to such participants or to such unaffiliated third party than as are set forth in our offer.
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Terminating Third-Party Contract Opportunities. To the extent Chesapeake or any of its affiliates is a party to any material gas gathering agreement or other material midstream energy services agreement with any third party covering services provided within an acreage dedication or any proximate area and such agreement becomes terminable by the applicable Chesapeake entity at no cost and without liability or is otherwise terminated, our omnibus agreement requires the applicable Chesapeake entity to provide us notice of such terminating third-party contract. Upon receipt of notice of such a terminating third-party contract, we have the right, exercisable within 60 days, to make an offer stating the terms pursuant to which we would be willing to provide the services provided by such contract. Unless Chesapeake Midstream Holdings rejects our offer by written notice to us within 60 days of the delivery of our offer, our offer will be deemed to have been accepted by Chesapeake Midstream Holdings, and the applicable Chesapeake entity will enter into an agreement with us for the provision of the services covered by our offer on the terms set forth therein. In the event that Chesapeake Midstream Holdings validly rejects the offer, it is be free to obtain the services covered by such terminating third-party contract from a third party, provided that such services are provided on terms and conditions no more favorable in the aggregate to such third party than as are set forth in our offer.
Monetization Transaction Opportunities. In the event that Chesapeake or any of its affiliates proposes to enter into any sale, transfer, disposition, joint venture or other monetization (whether involving assets or equity interests) of any midstream gathering systems and associated infrastructure assets located outside of the acreage dedications and the proximate areas, subject to certain exceptions, the applicable Chesapeake entity is required to first provide us with notice of such monetization transaction opportunity. Such notice must include any material terms, conditions and details (other than those relating to price, gas gathering and other commercial agreements to the extent not provided to any other third party in connection with the proposed transaction) as would be necessary for us to make a responsive offer to enter into the contemplated monetization transaction, which terms, conditions and details must at a minimum include any terms, conditions and details provided to third parties in connection with the proposed monetization transaction. Upon receipt of such notice, we have the right, exercisable within 60 days, to make an offer to the applicable Chesapeake entity to enter into the monetization transaction. Unless the applicable Chesapeake entity rejects our offer by written notice to us within 60 days of the delivery of our offer, our offer is deemed to have been accepted, and the applicable Chesapeake entity must enter into an agreement with us providing for the consummation of the monetization transaction on the terms set forth in our offer. If we do not make a valid offer in response to any such monetization opportunity, Chesapeake will be free to enter into such monetization opportunity with any third party on terms and conditions no more favorable to such third party than those set forth in the notice of such opportunity provided to us. In the event that the applicable Chesapeake entity validly rejects the offer, it is be free to enter into the monetization transaction with a third party, provided that (i) the terms and conditions of the transaction (including those relating to gas gathering and other commercial agreements, but excluding those relating to price) cannot be more favorable in the aggregate to such third party than as are set forth in our offer and (ii) such monetization transaction is at a price equal to no less than 95% of the price set forth in our offer. Notwithstanding the foregoing, Chesapeake and its affiliates will not be required to provide us with a right of first offer with respect to the following types of transactions:
| • | equity financing transactions by Chesapeake in respect of any midstream gathering systems and/or associated infrastructure located outside of the acreage dedications and the proximate areas, the net proceeds of which are used to finance the construction, development and/or operation of such midstream gathering systems and/or associated infrastructure assets; |
| • | any financing transactions consisting of debt that is non-convertible and non-exchangeable, provided that any such transaction or series of related transactions may include the issuance of equity interests to the parties providing financing or affiliates thereof that in the aggregate constitute less than 20% of the aggregate value of such financing transaction; |
| • | any transactions that would result in a change of control of Chesapeake or a sale of all or substantially all of the assets of Chesapeake and its subsidiaries, taken as a whole; |
| • | any sale, joint venture or other monetization of any midstream gathering system and/or associated infrastructure assets outside the acreage dedications and the proximate areas in connection with a sale of interests in oil and gas properties (including, but not limited to, volumetric production payments) in which the majority of the assets (by value) are comprised of oil and gas exploration and production assets; |
| • | any transaction that was subject to a right of first refusal, purchase or similar commitment to a third party as of September 30, 2009; |
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| • | any exchange, swap or similar property-for-property transaction involving the exchange of any midstream gathering system and/or associated infrastructure assets outside the acreage dedications and the proximate areas for other midstream gathering systems and/or associated infrastructure assets outside the acreage dedications and the proximate areas, to the extent any net cash proceeds to Chesapeake from any such |
| • | transaction or series of related transactions does not comprise more than 20% of the aggregate value of the assets subject to such transaction or series of related transactions; and |
| • | any sale, transfer or disposition to a 100% affiliate of Chesapeake that remains a 100% affiliate of Chesapeake at all times following such sale, transfer or disposition. |
With respect to the fifth bullet listed above, a third party has a right of first refusal covering Chesapeake’s midstream assets in the Marcellus Shale that has priority over our right of first offer applicable to any monetization of those assets by Chesapeake.
Chesapeake’s obligations to provide us with the business opportunities outlined above may be terminated by Chesapeake at any time each of GIP and Chesapeake holds less than half of the ownership interest it held in Chesapeake Midstream Ventures as of the closing of this offering.
Indemnification. Pursuant to the omnibus agreement, we are entitled to indemnification for certain liabilities, and we are required to indemnify Chesapeake Midstream Ventures for certain liabilities.
Chesapeake Midstream Ventures’ indemnification obligations to us include the following:
| • | Environmental. For a period of three years following the closing of our initial public offering in August 2010, Chesapeake Midstream Ventures is obligated to indemnify us for environmental losses by reason of, or arising out of, any violation, event, circumstance, action, omission or condition associated with the operation of our assets prior to the closing of the initial public offering, including: (i) any violation of or cost to correct a violation of any environmental laws, (ii) any environmental activity to address a release of hazardous substances and (iii) the release of, or exposure of any person to, any hazardous substance; provided, however, that (x) the aggregate liability of Chesapeake Midstream Ventures for environmental losses shall not exceed $15.0 million in the aggregate and (y) Chesapeake Midstream Ventures is only liable to provide indemnification for environmental losses to the extent that the aggregate dollar amount of losses suffered by us exceed $250,000. In no event does Chesapeake Midstream Ventures have any indemnification obligations under the omnibus agreement for any claim made as a result of additions to or modifications of current environmental laws enacted after the effective date of the omnibus agreement. |
| • | Title. For a period of three years after the closing of the initial public offering, Chesapeake Midstream Ventures will indemnify us for losses relating to our failure to be the owner as of the closing of this offering of valid and indefeasible easement rights, leasehold and/or fee ownership interests in and to the lands on which our assets are located, and such failure renders us liable to a third party or unable to use or operate our assets in substantially the same manner that our assets were used and operated immediately prior to the closing of this offering. |
| • | Governmental consents and permits. For a period of three years following the closing of our initial public offering in August 2010, Chesapeake Midstream Ventures is obligated to indemnify us for losses relating to our failure to have any consent or governmental permit necessary to allow (i) the transfer of any of our assets to us upon in connection with our initial public offering or (ii) any of our assets to cross the roads, waterways, railroads and other areas upon which any our assets are located as of the closing of our initial public offering, and any such failure specified in such clause (ii) renders us unable to use or operate our assets in substantially the same manner that our assets were used and operated immediately prior to our initial public offering. |
| • | Taxes. Until the first day after the expiration of any applicable statute of limitations, Chesapeake Midstream Ventures is obligated to indemnify us for losses in respect of or arising from all federal, state and local income tax liabilities attributable to the ownership or operation of our assets prior to the closing of our initial public offering in August 2010. |
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In no event will Chesapeake Midstream Ventures be obligated to indemnify us for any claims, losses or expenses or income taxes referred to above to the extent such claims, losses or expenses or income taxes were either (i) reserved for in our financial statements as of the effective date of the omnibus agreement or (ii) are recovered under available insurance coverage, from contractual rights or other recoveries against any third party. Under the omnibus agreement, we agree to use commercially reasonable efforts to realize any applicable insurance proceeds and amounts recoverable under such contractual obligations.
We have agreed to indemnify Chesapeake Midstream Ventures, and the officers, directors, employees, agents and representatives of Chesapeake Midstream Ventures from and against all losses to the extent that such losses are in respect of or arise from events and conditions associated with the operation of our assets and occurring on or after the closing of our initial public offering in 2010, unless in any such case indemnification is of a type that would not be permitted under our partnership agreement.
Services Agreement
We, our general partner, Chesapeake MLP Operating, L.L.C. and certain affiliates of Chesapeake have entered into an amended and restated services agreement that requires Chesapeake to provide general and administrative services and additional services to us in return for a reimbursement of certain of its expenses in connection therewith.
The table below sets forth the amount of general and administrative expenses for which we were be obligated to reimburse Chesapeake pursuant to the services agreement for the year ended December 31, 2010.
| December 31, 2010 | ||||
| (In millions) | ||||
| Reimbursement for general and administrative services (including a portion of certain incremental costs and expenses we incurred as a result of being a publicly traded partnership, which were approximately $2.0 million in 2010) |
$ | 17.0 | ||
General and Administrative Services and Reimbursement. Under the services agreement, Chesapeake performs centralized corporate functions for us, including human resources, information technology, treasury, risk management, legal, executive management, security, environmental, regulatory, production control, supervisory control and data application systems, gas measurement, internal audit, accounting, legal services, certain investor relations functions, volume control, contract management support and other required corporate services and functions requested by us. In return for such general and administrative services, our general partner has agreed to reimburse Chesapeake, based on agreed upon formulas pursuant to the services agreement, on a monthly basis for the time and materials actually spent in performing general and administrative services on our behalf. Our reimbursement to Chesapeake of such general and administrative expenses in any given month is subject to a cap in an amount equal to $0.03025 per Mcf multiplied by the volume (measured in Mcf) of natural gas that we gather, transport or process, subject to an annual escalation. The $0.03025 per Mcf cap is subject to an annual upward adjustment each year as of October 1 equal to 50% of any increase in the Consumer Price Index and, subject to receipt of requisite approvals, such cap may be further adjusted to reflect changes in the general and administrative services provided by Chesapeake relating to new laws or accounting rules that are implemented.
The cap contained in the services agreement does not apply to the additional services reimbursement described below. Additionally, the cap does not apply to our direct general and administrative expenses and may not apply to certain of the incremental general and administrative expenses that we incur as a result of becoming a publicly traded partnership.
Additional Services and Reimbursement. Chesapeake has agreed to provide us with certain additional services, at our request, under the services agreement, including engineering, construction, procurement, business analysis, commercial, cartographic and other similar services to the extent they are not already provided by the seconded employees. In return for such additional services, our general partner has agreed to reimburse Chesapeake on a monthly basis an amount equal to the time and materials actually spent in performing the additional services. The reimbursement for additional services is not subject to the general and administrative services reimbursement cap.
Chesapeake has agreed to perform all services under the relevant provisions of the services agreement using at least the same level of care, quality, timeliness and skill as it does for itself and its affiliates and with no less than the same degree of care, quality, timeliness and skill as its past practice in performing the services for itself and our business during the one year period prior to September 30, 2009. In any event, Chesapeake has agreed to perform such services using no less than a reasonable level of care in accordance with industry standards.
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In connection with the services arrangement, we have agreed to reimburse GIP for certain costs incurred by GIP in connection with assisting us in the operation of our business. For the twelve months ending December 31, 2010, we reimbursed GIP approximately $0.9 million for these support services.
The term of the services agreement will extend for additional twelve-month periods unless any party provides 180 days’ prior written notice otherwise prior to the expiration of the initial term ending December 31, 2011 or the applicable twelve-month period; provided that, on December 31, 2011, our general partner has the right to extend the term of the services agreement through June 30, 2012, regardless of any other party providing notice to terminate. In such a situation, the services agreement would automatically terminate on June 30, 2012.
Indemnification. Pursuant to the services agreement, certain affiliates of Chesapeake (the “Chesapeake Affiliates”) have agreed to indemnify our general partner and its subsidiaries, Chesapeake MLP Operating, L.L.C. and us (collectively, the “Partnership Group”) from and against certain potential claims, losses and expenses attributable to (i) breaches by the Chesapeake Affiliates of the services agreement, (ii) acts or omissions by the Chesapeake Affiliates in providing services in breach of the standard of performance set forth in the services agreement and (iii) claims by a third party relating to (A) breaches by the Chesapeake Affiliates of the services agreement, or (B) the Chesapeake Affiliates’ gross negligence or willful misconduct.
Additionally, the Partnership Group has agreed to indemnify the Chesapeake Affiliates from and against certain potential claims, losses and expenses attributable to (i) breaches by the Partnership Group of the services agreement or (ii) claims by a third party relating to (A) any acts or omissions of the Chesapeake Affiliates in connection with their performance of the services outlined in the services agreement, solely to the extent that (x) such acts or omissions were performed or omitted at the direction of our general partner, and without material deviation therefrom, and (y) such services were performed in accordance with the standard of performance set forth in the services agreement, or (B) the Partnership Group’s gross negligence or willful misconduct.
Employee Secondment Agreement
Chesapeake, certain of its affiliates and our general partner have entered into an amended and restated employee secondment agreement pursuant to which specified employees of Chesapeake have been seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Additionally, all of our executive officers other than our chief executive officer, Mr. Stice, have been seconded to our general partner pursuant to this agreement. Our general partner, subject to specified exceptions and limitations, reimburses Chesapeake on a monthly basis for substantially all costs and expenses Chesapeake incurs relating to such seconded employees, including the cost of their salaries, bonuses and employee benefits, including 401(k), restricted stock grants and health insurance and certain severance benefits. For the twelve months ending December 31, 2010, our general partner reimbursed Chesapeake approximately $30.3 million for the services rendered by such seconded employees during such period.
The initial term of the employee secondment agreement extends through September 30, 2014. The term will automatically extend for additional twelve month periods unless any party provides 90 days’ prior written notice otherwise prior to the expiration of the initial term or the applicable twelve month period. Our general partner may terminate the agreement at any time upon 90 days’ prior written notice.
Employee Transfer Agreement
In order to provide for an efficient transition of seconded employees from their current joint employment relationship with our general partner and Chesapeake in the event that our general partner elects to establish a standalone workforce, Chesapeake, certain of its affiliates and our general partner entered into an amended and restated employee transfer agreement pursuant to which our general partner agreed to maintain certain compensation and benefits standards for seconded employees to whom our general partner makes offers of employment. Among other things, the employee transfer agreement limits the ability of our general partner to hire seconded employees from Chesapeake to situations where our general partner offers such seconded employee a base salary or hourly base wages, equal or greater than that which Chesapeake provides such seconded employee at the time of transfer and other compensation and benefits that, in the aggregate, are substantially comparable to those provided to such seconded employee at such time. Additionally, in the event of such an employee transfer, for a period of not less than twelve months thereafter, we are obligated to maintain the base salary or hourly wages, for such transferred employee of no less than that paid to such transferred employee immediately prior to the transfer date and other compensation and benefits for such transferred employee that, in the aggregate, are substantially comparable to those in effect immediately prior to the transfer date.
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The employee transfer agreement has an indefinite term. However, the agreement is terminable (i) by the parties upon their mutual agreement, (ii) by any party upon another party’s failure to cure a material breach for 120 days, or (iii) by any party in the event that another party becomes insolvent.
Shared Services Agreement
In return for the services of Mr. Stice as the chief executive officer of our general partner, our general partner has entered into a shared services agreement with Chesapeake pursuant to which our general partner has agreed to reimburse certain of the costs and expenses incurred by Chesapeake in connection with Mr. Stice’s employment. Our general partner is generally expected, subject to certain exceptions, to reimburse Chesapeake for 50% of the costs and expenses of the amounts provided to Mr. Stice in his employment agreement; however, the ultimate reimbursement obligation is determined based on the amount of time Mr. Stice actually spends working for us. The reimbursement obligations of our general partner will continue for so long as Mr. Stice is employed by both our general partner and Chesapeake. Please read “Item 11. Executive Compensation—Employment Agreements—Agreement with J. Mike Stice, President and Chief Executive Officer” for a description of the costs, expenses and benefits afforded to Mr. Stice in connection with his employment agreement.
Gas Gathering Agreements
We have also entered into a gas gathering agreement in connection with our acquisition of the Springridge natural gas gathering system. For a discussion of the Springridge gas gathering agreement, please see “—Springridge Acquisition—Springridge Gas Gathering Agreement.”
We have entered into 20-year natural gas gathering agreements with certain subsidiaries of Chesapeake and with Total pursuant to which we provide gathering, treating, compression and dehydration services for natural gas delivered by Chesapeake and Total to our gathering systems in our Barnett Shale region and, solely with respect to Chesapeake, our Mid-Continent region. Total Holdings USA Inc., a wholly owned subsidiary of Total S.A., has guaranteed the obligations of Total Gas & Power North America, Inc. and Total E&P USA, Inc. under the Total gas gathering agreement. These agreements provide us with dedication of all of the natural gas owned or controlled by Chesapeake and Total and produced from or attributable to existing and future wells located on oil, gas and mineral leases covering lands within the acreage dedications, excluding (i) any oil, gas and/or mineral leases purchased, in the case of Chesapeake after September 30, 2009, and in the case of Total after February 1, 2010, that were, at the time of purchase, subject to dedication to another gas gathering system not owned and operated by Chesapeake, and such dedication was not entered into in connection with such acquisition; (ii) certain reserved properties specified in the gas gathering agreement; and (iii) other non-material properties dedicated as of September 30, 2009 in the case of Chesapeake, or as of February 1, 2010, in the case of Total to another gas gathering system not owned and operated by Chesapeake. We generated substantially all of our $459.2 million of revenues for the twelve months ending December 31, 2010 pursuant to these gas gathering agreements.
Pursuant to our gas gathering agreements, Chesapeake and Total have committed to deliver specified minimum volumes of natural gas to our gathering systems that take production from the Barnett Shale for each year through December 31, 2018 and for the six month period ending June 30, 2019. The aggregate minimum volume commitments, approximately 75% of which will be attributed to Chesapeake and approximately 25% of which will be attributed to Total, begin at approximately 418 Bcf for the year ending December 31, 2010 (or an average of approximately 1.14 Bcf/d) and increase on an annual basis pursuant to the terms of the gas gathering agreement to approximately 493 Bcf for the year ending December 31, 2018 (or an average of 1.35 Bcf/d). Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Gas Gathering Agreements.” The minimum volume commitments may be reduced in certain instances, including a force majeure event affecting a system, a delayed connection or to the extent a system is unavailable due to inspections, alterations or repairs in excess of five days per month. In the event either Chesapeake or Total does not meet its minimum volume commitment to us, as adjusted in certain instances, for any annual period (or six-month period in the case of the six months ending June 30, 2019) during the minimum volume commitment period, Chesapeake or Total will be obligated to pay us a fee equal to the Barnett Shale fee for each Mcf by which the applicable party’s minimum volume commitment for the year (or six-month period) exceeds the actual volumes gathered on our systems attributable to the applicable party’s production. To the extent natural gas gathered on our systems from Chesapeake or Total during any annual period (or six-month period) exceeds such party’s minimum volume commitment for the period, Chesapeake or Total will be obligated to pay us the Barnett Shale fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitment of such party for the six months ending June 30, 2019 and then against the minimum volume commitments of each preceding year. In the event that the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the immediately preceding period.
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We have certain connection obligations for new operated drilling pads and operated wells of Chesapeake and Total in the acreage dedications. Chesapeake and Total are required to provide us notice of new drilling pads and wells operated by Chesapeake or Total in the acreage dedications. During the minimum volume commitment period and subject to certain conditions specified in the gas gathering agreements, we are generally required to connect new operated drilling pads in the Barnett acreage dedication by the later of the date the wells commence production or 21 months after the date of the connection notice and, until June 30, 2019, to use our commercially reasonable efforts to connect new operated wells in the Mid-Continent area by the later of the date the wells commence production or 60 days after the date of the connection notice. If we fail to complete a connection in the Barnett acreage dedication by the required date, Chesapeake and Total, as their sole remedy for such delayed connection, are entitled to a delay in the minimum volume obligations for gas volumes that would have been produced from the delayed connection. After June 30, 2019, we only are required to make connections in the acreage dedications to new drilling pads and wells if we believe that the then current fees would allow us to earn an acceptable return on our investment, and if we decline to make a connection, Chesapeake and Total have certain rights to reimburse us for our connection costs or to request a release from the gathering agreement dedication of the affected wells. Chesapeake and Total also are required to notify us of their wells drilled in the acreage dedications that are operated by other parties and we have the option, but not the obligation, to connect non-operated wells to our gathering systems. If we decline to make a connection to a non-operated well, Chesapeake or Total, as the case may be, have certain rights to have the well released from the dedication under the gas gathering agreement.
A maximum daily quantity is also in effect with respect to the gathering systems that take production from the Barnett Shale. Generally, once daily volumes equal the maximum quantity specified for a particular system, we are no longer obligated to accept natural gas on such system. Under certain circumstances, however, where excess capacity is then available on an applicable gathering system, we may be required to accept such natural gas to the extent available and to provide “Priority 3 Service” with respect to such volumes. In most instances (and, where applicable, up to the maximum daily quantity), Chesapeake and Total are entitled to “Priority 1 Service.” If capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, the holders of Priority 1 Service will be curtailed last. Subject to certain limitations, we may commingle Chesapeake’s and Total’s natural gas with the natural gas of third parties.
Volumetric losses in Chesapeake’s or Total’s natural gas attributable to lost and unaccounted for natural gas, as well as volumetric reductions related to the use of fuel gas for gathering, compression, dehydrating, processing and treating, are, with respect to a particular gathering system, shared and allocated among Chesapeake, Total and other third-party shippers in the proportion that each party delivers gas to such system. We have agreed with Chesapeake on MMBtu-based caps on fuel, lost and unaccounted for gas on certain of our systems with respect to Chesapeake’s volumes in our Barnett Shale and Mid-Continent regions. In the event that 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.
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The agreements are fee-based, and we are paid a specified fee per Mcf for natural gas received on our gathering systems. The particular fees, which are subject to an automatic annual escalator at the beginning of each year, differ from one system to another and, in some cases, are based in part upon receipt point pressures. At specified intervals, we and each of Chesapeake and Total have the right to seek a redetermination of the fees for service on the Barnett gathering system. Such rights may be exercised during a six-month period beginning September 30, 2011 and a two-year period beginning September 30, 2014. A fee redetermination with respect to our Barnett Shale region under either agreement will apply to volumes from Chesapeake and Total under both agreements. The cumulative upward or downward fee adjustment for the Barnett Shale region is capped at 27.5% of the initial weighted average Barnett Shale fee (as escalated) as specified in the gas gathering agreement. The fee redetermination mechanism was designed to support a return on our invested capital as we meet our obligation to connect our customers’ operated wells to our gathering systems. An example of such variation may be the variation in fees generated on those systems where the fee is based in part upon receipt point pressures. If a fee redetermination is requested, we will determine an adjustment (upward or downward) to our Barnett Shale fee with Chesapeake and Total based on the factors specified in our gas gathering agreements, including, but not limited to: (i) differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the minimum volume commitment period made as of September 30, 2009 and (ii) differences between the revised estimates of our capital expenditures, compression expenses and revenues for the remainder of the minimum volume commitment period forecast as of the redetermination date and scheduled estimates thereof for the minimum volume commitment period made as of September 30, 2009. If we and Chesapeake or Total do not agree upon a redetermination of the Barnett Shale fee within 30 days of receipt of the request for the redetermination, an industry expert will be selected to determine adjustments to the Barnett Shale fee. A redetermined Barnett Shale fee will go into effect on the first day of the month following the date on which the adjusted fee is finally determined. The Mid-Continent fees will be redetermined at the beginning of each year through 2019. We will determine an adjustment to fees for the gathering systems in the region with Chesapeake based on the factors specified in the gas gathering agreement, including, but not limited to differences between our actual revenues, capital expenditures and compression expenses as of the redetermination date and the scheduled estimates of these amounts for the period ending June 30, 2019, referred to as the Mid-Continent redetermination period, made as of September 30, 2009. The annual upward or downward fee adjustment for the Mid-Continent region is capped at 15% of the then current fees at the time of redetermination.
Chesapeake continues to own the gathering system located on the property leased from the Dallas-Fort Worth (“DFW”) Airport Authority in the Barnett Shale region, and we have been engaged to operate and maintain this gathering system. We receive as a fee for providing the operation and maintenance services an amount equal to all revenues derived from the operation of the DFW gathering system while we serve as the operator, including the fees paid by Chesapeake and Total under our gas gathering agreements. If our right to operate and maintain the DFW gathering system is terminated, Chesapeake is obligated to make a termination payment to us that equals the economic benefits we would have received if such termination had not occurred and to indemnify us for any other losses arising from such early termination.
The primary terms of the agreements continue through June 30, 2029, after which the agreements continue in effect on a year-to-year basis unless terminated by either party. We may terminate our gas gathering agreement with Chesapeake or Total if Chesapeake or Total fails to perform any of its material obligations, such failure is not excused by force majeure events and such failure is not remedied (or remedial action commenced) during a 60-day cure period. Chesapeake or Total may terminate if we fail to perform any of our material obligations. However, if our failure relates to only one or more facilities or gathering systems, Chesapeake or Total may terminate only as to such facility or system. Where Chesapeake or Total fails to pay us an undisputed amount when due, we may terminate if such failure is not remedied within 15 business days after we provide notice to Chesapeake or Total of such failure. We have entered into a guaranty with Chesapeake relating to, among other agreements, our gas gathering agreement with certain of its affiliates. The guaranty provided by Chesapeake is a guaranty of payment and performance and not of collection.
In the event that either Chesapeake or Total sells, transfers or otherwise disposes to a third party properties within the acreage dedication in our Barnett Shale region and, solely with respect to Chesapeake, our Mid-Continent region, it will be required to cause the third party to either enter into our existing gas gathering agreement with Chesapeake or Total or enter into a new gas gathering agreement with us on substantially similar terms to our existing gas gathering agreement with Chesapeake or Total.
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Gas Compressor Master Rental and Servicing Agreement
We have entered into a gas compressor master rental and servicing agreement with MidCon Compression, LLC, a wholly owned indirect subsidiary of Chesapeake, pursuant to which MidCon Compression has agreed to lease to us certain compression equipment that we use to compress gas gathered on our gathering systems and provide certain related services. In return for the lease of such equipment, we have agreed to pay specified monthly rates per specified compression units, subject to an annual escalator to be applied on October 1st of each year and a redetermination of such specified monthly rates to market rates effective no later than October 1, 2016. Under the compression agreement, we have granted MidCon Compression the exclusive right to lease and rent compression equipment to us in the acreage dedications through September 30, 2016. Thereafter, we will have the right to continue leasing such equipment through September 30, 2019 at market rental rates to be agreed upon between the parties or to lease compression equipment from unaffiliated third parties. MidCon Compression guarantees to us that the leased compressors will meet specified run time and throughput performance guarantees. The monthly rental rates are reduced for any leased equipment that does not meet these guarantees. We incurred compression expenses of $47.8 million for the twelve months ending December 31, 2010 pursuant to the gas compressor master rental and servicing agreement.
We are obligated to maintain general liability and property insurance, including machinery breakdown insurance with respect to the leased equipment. In addition, MidCon Compression has agreed to provide us with emission testing and other related services at monthly rates. We may terminate these services upon not less than six months notice, and MidCon Compression may terminate these services at any time after September 30, 2011 upon not less than six months notice.
The compression agreement expires on September 30, 2019 but will continue from year to year thereafter, unless terminated by us no less than 60 days prior to the end of the term or any year thereafter. Additionally, either party may terminate in specified circumstances, including upon the other party’s failure to perform material obligations under the compression agreement if such failure is not cured within 60 days after notice thereof.
In connection with the acquisition, on December 21, 2010, this agreement was amended and restated to include the area of mutual interest associated with the Springridge natural gas gathering system and to allow for the addition of future areas of mutual interest. For a discussion of the terms of the compression agreement, please see “—Agreements with Affiliates—Gas Compressor Master Rental and Servicing Agreement.”
Inventory Purchase Agreement
We have entered into an inventory purchase agreement pursuant to which we have agreed beginning as of September 30, 2009 to purchase from Chesapeake, in each case on terms and conditions to be mutually agreed upon by Chesapeake and us, our first $60.0 million of requirements of pipes that are useful in the conduct of the natural gas gathering, compression, dehydrating, treating and transportation business at a specified price per ton. We purchased $36.6 million of inventory through December 31, 2010, pursuant to this inventory purchase agreement.
Marketing and Noncompete Agreement
Pursuant to a marketing and noncompete agreement, we have agreed to appoint Chesapeake Energy Marketing, Inc., a wholly owned indirect subsidiary of Chesapeake (which we refer to as CEMI), as our agent to purchase, at our request, gas on behalf of us, at agreed market responsive prices and for an agreed marketing fee, to settle accrued gas imbalances on our gathering systems. As consideration for such agreement, we have agreed to not engage in activities to purchase or market natural gas in the acreage dedications if CEMI or its affiliates are then performing, or willing to perform, such activities on our behalf. Additionally, each of CEMI and Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P. and DD Jet Limited, LLP, each wholly owned indirect subsidiaries of Chesapeake, has agreed not to, and to cause Chesapeake not to, directly or indirectly, engage in or participate in activities to gather or transport natural gas in the acreage dedications, whether for their own account or on behalf of third parties.
The marketing and noncompete agreement expires on September 30, 2019 but will continue from month to month thereafter, unless terminated by either party upon no less than 30 days’ prior notice. Additionally, either party may terminate in specified circumstances, including upon the other party’s failure to perform material obligations under the compression agreement if such failure is not cured within 60 days after notice thereof.
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Master Recoupment, Netting and Setoff Agreement
We have entered into a master recoupment, netting and setoff agreement with Chesapeake and certain of its subsidiaries. The recoupment agreement provides for the netting of fees, liquidated damages and other charges between the parties to certain “covered agreements,” including the gas gathering agreement with Chesapeake, the gas compressor master rental and servicing agreement, the services agreement, the employee secondment agreement and the employee transfer agreement. The recoupment agreement provides for the parties’ right to recoup, net and setoff accrued and unpaid fees, reimbursements, late payment charges and interest, and liquidated damages for breach or early termination pursuant to specified obligations arising under the terms of the covered agreements and losses, damages and other amounts to the extent agreed by the parties or provided by a court order. Recoupment, netting and setoff rights are triggered by a “recoupment event,” defined as the failure to pay an accrued payment obligation or obligations exceeding $100,000 under a covered agreement. Under the agreement, if a “triggering event,” defined as bankruptcy or insolvency, occurs, the non-bankrupt/insolvent party has the right to hold funds due from it to the bankrupt/insolvent party as an offset to liquidated amounts due from the bankrupt/insolvent party to the non-bankrupt/insolvent party, pending resolution of the parties’ rights under the recoupment agreement or common law. This agreement will terminate in the event there are fewer than two “covered agreements” in effect, or earlier upon written agreement of the parties.
Surety Bond Indemnification Agreement
We have agreed to indemnify Chesapeake and certain affiliates of Chesapeake against any loss or expense with respect to certain surety bonds issued for our benefit and for which we are obligated to provide indemnity insurance to Chesapeake. We may also be required to indemnify Chesapeake in connection with future surety bond issuances made for our benefit. Our currently outstanding surety bonds relate to certain well, pipeline and litigation obligations in New Mexico, Oklahoma and Texas. These indemnification obligations will not expire until all bond obligations for which we are liable for indemnification to Chesapeake are released.
Trademark License Agreement
We have entered into a trademark license agreement with Chesapeake Energy Corporation pursuant to which it has agreed to grant to us a license to use the mark “Chesapeake” in the trade name and service mark “Chesapeake Midstream Partners.” Such license is a royalty-free, fully paid up, nonexclusive and nontransferable right and license to use such marks solely in connection with the midstream natural gas business. Subject to certain exceptions, the trademark license agreement will continue until December 31, 2019. Either party may terminate in the event of a material breach by the other party that is not cured within 30 days of written notice thereof.
Registration Rights Agreement
We have entered into a registration rights agreement with Chesapeake and GIP pursuant to which we have granted each of Chesapeake and GIP and certain of their affiliates certain demand and “piggyback” registration rights. Under the registration rights agreement, each of Chesapeake and GIP and certain of their affiliates generally have the right to require us to file a registration statement for the public sale of all of the equity interests in the Partnership, including common and subordinated units and incentive distribution rights (collectively, “partnership securities”) owned by it. In addition, if we sell any partnership securities in a registered underwritten offering, each of Chesapeake and GIP and certain of their affiliates have the right, subject to specified limitations, to include its partnership securities in that offering.
We are obligated to pay all expenses relating to any demand or piggyback registration, except for underwriters or brokers’ commission or discounts.
Springridge Acquisition
On December 16, 2010, we entered into an asset purchase agreement with Louisiana Midstream Gas Services, L.L.C., and Chesapeake Midstream Development, L.P. (collectively, the “Seller Parties”), and, for certain limited purposes, Chesapeake Midstream Management, L.L.C. All of the parties are subsidiaries or affiliates of Chesapeake. Pursuant to the terms of the purchase agreement, we agreed to acquire all of the Seller Parties’ right, title and interest in and to assets and assume certain liabilities associated with the Springridge natural gas gathering system in the Haynesville Shale, other than certain excluded assets and retained obligations.
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The acquisition closed on December 21, 2010, with an economic effective date of December 1, 2010. Terms of the transaction were approved by our general partner’s board of directors and by the board’s conflicts committee, which is comprised entirely of independent directors. The purchase price for the acquisition consisted of $500 million, subject to post-closing adjustment, which was financed with a draw on our revolving credit facility of approximately $234.0 million plus approximately $266.0 million of cash on hand.
Pursuant to the purchase agreement and subject to specified limitations, the Seller Parties have agreed to indemnify us, our affiliates, and the respective officers, directors, employees, partners, members, equity holders, agents and investment advisers of any of the foregoing against certain losses resulting from any breach of any representations, warranties and covenants of the Seller Parties, and for certain other matters. We agreed to indemnify the Seller Parties, their affiliates, and the respective officers, directors, employees, partners, members, equity holders, agents and investment advisers of any of the foregoing against certain losses resulting from any breach by us of any representations, warranties and covenants, and for certain other matters.
All of the parties to the acquisition and related agreements described herein are subsidiaries or affiliates of Chesapeake. The terms of the acquisition and related agreements were approved by our general partner’s board of directors and by the board’s conflicts committee. The conflicts committee, a committee comprised of the independent members of our general partner’s board of directors, retained independent legal and financial advisors to assist it in evaluating and negotiating the acquisition. In approving the acquisition, the conflicts committee based its decision in part on an opinion from the independent financial advisor that the consideration to be paid by us was fair, from a financial point of view, to us.
Springridge Gas Gathering Agreement.
In connection with the acquisition, on December 21, 2010, we entered into a 10-year natural gas gathering agreement with wholly-owned subsidiaries of Chesapeake, Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Empress, L.L.C. and Chesapeake Louisiana L.P. (collectively, “CHK Springridge”). Pursuant to the gas gathering agreement, we will provide gathering, treating, compression and dehydration services for natural gas delivered by CHK Springridge to our gathering system in the Springridge area of mutual interest. The gas gathering agreement provides us with a dedication of substantially all of the natural gas owned or controlled by CHK Springridge and produced from or attributable to existing and future wells located on oil, gas and mineral leases pertaining to the Haynesville and Bossier formations within the Springridge area of mutual interest.
Pursuant to the gas gathering agreement, CHK Springridge has committed to deliver specified minimum volumes of natural gas to our Springridge gathering system for each year from 2011 through 2013. The aggregate minimum volume commitments begin at approximately 103.7 Bcf for 2011 (or an average of approximately 0.284 Bcf/d) and increase on an annual basis pursuant to the terms of the gas gathering agreement to approximately 118.5 Bcf for 2012 (or an average of approximately 0.325 Bcf/d) and 134.6 Bcf for 2013 (or an average of 0.369 Bcf/d). T he minimum volume commitments may be reduced in certain instances. In the event CHK Springridge does not meet its minimum volume commitment, as adjusted in certain instances, for any annual period during the minimum volume commitment period, CHK Springridge will be obligated to pay us a fee equal to the Springridge fee for each Mcf by which CHK Springridge’s minimum volume commitment for the year exceeds the actual volumes gathered on the system attributable to CHK Springridge’s production. To the extent natural gas gathered on the system from CHK Springridge during any annual period exceeds CHK Springridge’s minimum volume commitment for the period, CHK Springridge will be obligated to pay us the Springridge fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitment of such CHK Springridge for 2013 and then against the minimum volume commitments of each preceding year. In the event that the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the immediately preceding period.
We have certain connection obligations similar to those under our existing gas gathering agreement in the Barnett Shale region. CHK Springridge is entitled to “Priority 1 Service.” If capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, the holders of Priority 1 Service will be curtailed last.
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Volumetric losses in CHK Springridge’s natural gas attributable to lost and unaccounted for natural gas, as well as volumetric reductions related to the use of fuel gas for gathering, compression, dehydrating, processing and treating, are, with respect to a particular gathering system, shared and allocated among CHK Springridge and other third-party shippers in the proportion that each party delivers gas to such system.
The gas gathering agreement is fee-based, and we are paid a specified fee per Mcf for natural gas received on our gathering system. Volumes of natural gas that receive compression service will be subject to an additional compression fee. The fees are subject to an automatic annual escalator at the beginning of each year. The agreement also contains a fee redetermination mechanism. The fee redetermination mechanism was designed to support a return on our invested capital as we meet our obligation to connect our customers’ operated wells to our gathering systems. The first redetermination period will extend from December 1, 2010 through December 31, 2012, and subsequent redetermation periods will be the calendar years 2013 through 2020. An adjustment to fees for the gathering systems in the region with CHK Springridge will be determined based on the factors specified in the gas gathering agreement, including, but not limited to differences between our actual revenues, capital expenditures and compression expenses as of the redetermination date and the scheduled estimates of these amounts for the period ending December 31, 2020, made as of November 30, 2010. The annual upward or downward fee adjustment is capped at 15% of the then prevailing fees at the time of redetermination. If we and CHK Springridge do not agree upon a redetermination of the fees within 30 days after the commencement of a new redetermination period, an industry expert will be selected to determine adjustments to the fees pursuant to the redetermination provisions in the agreement. Redetermined fees will go into effect on the first day of the month following the date on which the adjusted fee is finally determined.
The primary term of the agreement continues through December 31, 2020, after which the agreement continues in effect on a year-to-year basis unless terminated by either party. We have entered into a guaranty with Chesapeake relating to, among other agreements, the gas gathering agreement. The guaranty provided by Chesapeake is a guaranty of payment and performance and not of collection.
Amended and Restated Gas Compressor Master Rental and Servicing Agreement
In connection with the acquisition, our previously existing gas compressor master rental and servicing agreement with MidCon Compression, LLC, a wholly-owned indirect subsidiary of Chesapeake, was amended and restated, on terms substantially similar to those under our original compression agreement, to include the area of mutual interest associated with the Springridge natural gas gathering system and to allow for the addition of future area of mutual interest. For a discussion of the terms of the compression agreement, please see “—Agreements with Affiliates—Gas Compressor Master Rental and Servicing Agreement.”
Marketing and Noncompete Agreement
Pursuant to a marketing and noncompete agreement, we have agreed to appoint Chesapeake Energy Marketing, Inc., a wholly owned indirect subsidiary of Chesapeake (which we refer to as CEMI), as our agent to purchase, at our request, gas on behalf of us, at agreed market responsive prices and for an agreed marketing fee, to settle accrued gas imbalances on our gathering systems. As consideration for such agreement, we have agreed to not engage in or participate in activities to purchase or market natural gas in the acreage dedication if CEMI or its affiliates are then performing, or willing to perform, such activities on our behalf. Additionally, each of CEMI and Chesapeake Louisiana L.P. and Empress, L.L.C., each wholly owned indirect subsidiaries of Chesapeake, has agreed not to, and to cause Chesapeake not to, directly or indirectly, engage in or participate in activities to gather or transport natural gas in the acreage dedication, whether for their own account or on behalf of third parties.
The marketing and noncompete agreement expires on December 31, 2020 but will continue from month to month thereafter, unless terminated by either party upon no less than 30 days’ prior notice. Additionally, either party may terminate in specified circumstances, including upon the other party’s failure to perform material obligations under the marketing and noncompete agreement if such failure is not cured within 60 days after notice thereof.
Review, Approval or Ratification of Transactions with Related Persons
Our Code of Ethics sets forth our policies for the review, approval and ratification of transactions with related persons. Under the Code of Ethics, a director is expected to bring to the attention of the chief executive officer or the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict will be addressed in accordance with Chesapeake Midstream Venture’s and our general partner’s organizational documents and the provisions of our partnership agreement. The resolution may be determined by disinterested directors, our general partner’s board of directors and/or the conflicts committee of our general partner’s board of directors.
Pursuant to the Code of Ethics, any executive officer of our general partner is required to avoid conflicts of interest unless approved by the board of directors.
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.
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Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Chesapeake, GIP and Chesapeake Midstream Ventures, on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of its fiduciary duty.
Our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our unitholders if the resolution of the conflict is:
| • | approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval; |
| • | approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates; |
| • | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
| • | fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
Our general partner may, but is not required under our partnership agreement to, seek the approval of such resolution from the conflicts committee of its board of directors. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to reasonably believe he is acting in the best interests of the partnership.
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.”
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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:
| 2010 | ||||
| (in thousands) | ||||
| Audit fees |
$ | 920 | ||
| Audit-related fees |
150 | |||
| Tax |
183 | |||
| All other fees |
— | |||
| Total |
1,253 | |||
Audit fees are primarily for IPO related fees and audit of the Partnership’s consolidated financial statements and reviews of the Partnership’s financial statements included in the Form 10-Qs.
Audit related fees include the audit and review, respectively, of the Springridge gas gathering system financial statements for the year ended December 31, 2009, and nine months ended September 30, 2010.
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 2010, 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, 2010
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| ITEM 15. | Exhibits and Financial Statement Schedules |
| (a) | The following documents are filed as part of this report: |
| 1. | Financial Statements. Chesapeake’s consolidated financial statements are included in Item 8 of this report. Reference is made to the accompanying Index to Financial Statements. |
| 2. | Financial Statement Schedules. Schedule II is included in Item 8 of this report with our consolidated financial statements. No other financial statement schedules are applicable or required. |
| 3. | Exhibits. The following exhibits are filed herewith pursuant to the requirements of Item 601 of Regulation S-K: |
| Incorporated by Reference |
||||||||||||||
| Exhibit Number |
Exhibit Description |
Form |
SEC File Number |
Exhibit |
Filing Date |
Filed Herewith |
Furnished Herewith | |||||||
| 2.1 | Asset Purchase Agreement by and among Louisiana Midstream Gas Services, L.L.C., Chesapeake Midstream Development, L.P. and Magnolia Midstream Gas Services L.L.C., and, for certain limited purposes, Chesapeake Midstream Management, L.L.C., dated as of December 16, 2010 |
8-K | 001-34831 | 2.1 | 12/22/2010 | |||||||||
| 3.1 | Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. |
S-1 | 333-164905 | 3.1 | 02/16/2010 | |||||||||
| 3.2 | First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. dated August 3, 2010. |
8-K | 001-34831 | 3.1 | 08/05/2010 | |||||||||
| 3.3 | Second Amended and Restated Limited Liability Company Agreement of Chesapeake MLP Operating, L.L.C., dated August 3, 2010. |
8-K | 001-34831 | 3.2 | 08/05/2010 | |||||||||
| 10.1 | Underwriting Agreement, dated July 28, 2010, by and among Chesapeake Midstream Partners, L.P., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Ventures, L.L.C., Chesapeake MLP Operating, L.L.C and the Underwriters named therein. |
8-K | 001-34831 | 1.1 | 07/30/2010 | |||||||||
| 10.2 | Contribution, Conveyance and Assumption Agreement by and among Chesapeake Midstream Partners, L.P., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Holdings, L.L.C., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P., Chesapeake Midstream Ventures, L.L.C. and Chesapeake MLP Operating, L.L.C., dated as of July 28, 2010. |
8-K | 001-34831 | 10.1 | 07/30/2010 | |||||||||
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| Incorporated by Reference |
||||||||||||||
| Exhibit Number |
Exhibit Description |
Form |
SEC File Number |
Exhibit |
Filing Date |
Filed Herewith |
Furnished Herewith | |||||||
| 10.3 | Omnibus Agreement by and among Chesapeake Midstream Holdings, L.L.C., Chesapeake Midstream Ventures, L.L.C. and Chesapeake Midstream Partners, L.P., dated August 3, 2010. |
8-K | 001-34831 | 10.1 | 08/05/2010 | |||||||||
| 10.4 | Amended and Restated Services Agreement by and among Chesapeake Midstream Management, L.L.C., Chesapeake Operating, Inc., Chesapeake Midstream GP, L.L.C, Chesapeake Midstream Partners, L.P. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010. |
8-K | 001-34831 | 10.2 | 08/05/2010 | |||||||||
| 10.5 | Amended and Restated Employee Transfer Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream Management, L.L.C., Chesapeake Midstream GP, L.L.C. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010. |
8-K | 001-34831 | 10.3 | 08/05/2010 | |||||||||
| 10.6 | Amended and Restated Employee Secondment Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream Management, L.L.C., Chesapeake Midstream GP, L.L.C., Chesapeake Operating, Inc. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010. |
8-K | 001-34831 | 10.4 | 08/05/2010 | |||||||||
| 10.7 | Amended and Restated Shared Services Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream GP, L.L.C., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010. |
8-K | 001-34831 | 10.5 | 08/05/2010 | |||||||||
| 10.8 | Registration Rights Agreement by and among Chesapeake Midstream Partners, L.P., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P. and Chesapeake Midstream Holdings, L.L.C., dated August 3, 2010. |
8-K | 001-34831 | 10.6 | 08/05/2010 | |||||||||
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| Incorporated by Reference |
||||||||||||||
| Exhibit Number |
Exhibit Description |
Form |
SEC File Number |
Exhibit |
Filing Date |
Filed Herewith |
Furnished Herewith | |||||||
| 10.9 | First Amendment to Credit Agreement among Chesapeake MLP Operating, L.L.C., as the Borrower, Chesapeake Midstream Partners, L.P., as the Parent, Wells Fargo Bank, National Association, as Administrative Agent, The Royal Bank of Scotland plc, as Syndication Agent, Bank of Montreal, Compass Bank and The Bank of Nova Scotia, as Co-Documentation Agents and the other Lenders party thereto, dated as of August 2, 2010. |
8-K | 001-34831 | 10.7 | 08/05/2010 | |||||||||
| 10.10* | Chesapeake Midstream Long-Term Incentive Plan. |
S-1 | 333-164905 | 10.18 | 07/20/2010 | |||||||||
| 10.10.1* | Form of Restricted Unit Award Agreement for Long-Term Incentive Plan |
X | ||||||||||||
| 10.11 | Amended and Restated Gas Gathering Agreement, dated January 25, 2010, by and among Chesapeake Midstream Partners, L.L.C., Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P. and DDJET Limited LLP. |
S-1 | 333-164905 | 10.2 | 07/26/2010 | |||||||||
| 10.12 | Barnett Gas Gathering Agreement, dated January 25, 2010, by and among Chesapeake Midstream Partners, L.L.C., Total Gas & Power North America, Inc. and Total E&P USA, Inc. |
S-1 | 333-164905 | 10.3 | 07/26/2010 | |||||||||
| 10.13† | Gas Gathering Agreement, dated December 21, 2010, by and among Magnolia Midstream Gas Services, L.L.C., Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Empress, L.L.C. and Chesapeake Louisiana L.P. |
X | ||||||||||||
| 10.14 | Gas Compressor Master Rental and Servicing Agreement, dated September 30, 2009, between Midcon Compression, LLC and Chesapeake Midstream Partners, L.L.C. |
S-1 | 333-164905 | 10.8 | 04/09/2010 | |||||||||
| 10.15† | Amended and Restated Gas Compressor Master Rental and Servicing Agreement, effective as of December 21, 2010, between MidCon Compression, LLC and Chesapeake MLP Operating, L.L.C. |
X | ||||||||||||
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| Incorporated by Reference |
||||||||||||||
| Exhibit Number |
Exhibit Description |
Form |
SEC File Number |
Exhibit |
Filing Date |
Filed Herewith |
Furnished Herewith | |||||||
| 10.16 | Additional Agreement, dated January 25, 2010, by and among Chesapeake Midstream Partners, L.L.C., Total Gas & Power North America, Inc., Total E&P USA, Inc., Chesapeake Energy Marketing, Inc., Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P., DDJET Limited LLP and Chesapeake Operating, Inc. |
S-1 | 333-164905 | 10.4 | 07/26/2010 | |||||||||
| 10.17* | Chesapeake Midstream Management Incentive Compensation Plan. |
S-1 | 333-164905 | 10.17 | 07/06/2010 | |||||||||
| 10.17.1* | Award Agreement under Chesapeake Midstream Management Incentive Compensation Plan-Robert S. Purgason. |
S-1 | 333-164905 | 10.20 | 07/06/2010 | |||||||||
| 10.17.2* | Award Agreement under Chesapeake Midstream Management Incentive Compensation Plan-David C. Shiels. |
S-1 | 333-164905 | 10.21 | 07/06/2010 | |||||||||
| 10.18* | Amended and Restated Employment Agreement of J. Mike Stice |
S-1 | 333-164905 | 10.12 | 07/06/2010 | |||||||||
| 10.19* | Amendment to Employment Agreement of J. Mike Stice |
S-1 | 333-164905 | 10.13 | 07/06/2010 | |||||||||
| 10.20* | Employment Agreement of Robert S. Purgason |
S-1 | 333-164905 | 10.14 | 07/06/2010 | |||||||||
| 10.21* | Employment Agreement of David C. Shiels |
S-1 | 333-164905 | 10.15 | 07/06/2010 | |||||||||
| 10.22† | Amendment to Amended and Restated Gas Gathering Agreement, dated March 8 2011, by and among Chesapeake Midstream Partners, L.L.C., Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P. and DDJET Limited LLP. |
X | ||||||||||||
| 21.1 | Subsidiaries of Chesapeake Midstream Partners, L.P. |
X | ||||||||||||
| 31.1 | J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
X | ||||||||||||
| 31.2 | David C. Shiels, Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
X | ||||||||||||
| 32.1 | J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
X | ||||||||||||
| 32.2 | David C. Shiels, Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
X | ||||||||||||
† Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
* Management contract or compensatory plan or arrangement.
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Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| CHESAPEAKE MIDSTREAM PARTNERS, L.P. | ||||||
| Date: March 11, 2011 |
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.
| Signature |
Capacity |
Date | ||
|
/s/ J. MIKE STICE |
Chief Executive Officer (Principal Executive Officer) |
March 11, 2011 | ||
| J. Mike Stice | ||||
| /s/ DAVID C. SHIELS |
Chief Financial Officer (Principal Financial Officer) |
March 11, 2011 | ||
| David C. Shiels | ||||
| /s/ BRADLEY D. MUELLER |
Controller | March 11, 2011 | ||
| Bradley D. Mueller | ||||
| /s/ DAVID A. DABERKO |
Chairman of the Board and Director | March 11, 2011 | ||
| David A. Daberko | ||||
| /s/ PHILIP L. FREDERICKSON |
Director | March 11, 2011 | ||
| Philip L. Frederickson | ||||
| /s/ MATTHEW C. HARRIS |
Director | March 11, 2011 | ||
| Matthew C. Harris | ||||
| /s/ SUEDEEN G. KELLY |
Director | March 11, 2011 | ||
| Suedeen G. Kelly | ||||
| /s/ AUBREY K. MCCLENDON |
Director | March 11, 2011 | ||
| Aubrey K. McClendon | ||||
| /s/ MARCUS C. ROWLAND |
Director | March 11, 2011 | ||
| Marcus C. Rowland | ||||
| /s/ WILLIAM A. WOODBURN |
Director | March 11, 2011 | ||
| William A. Woodburn | ||||
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INDEX TO EXHIBITS
| Incorporated by Reference |
||||||||||||||||||||
| Exhibit |
Exhibit Description |
Form |
SEC File Number |
Exhibit | Filing Date | Filed Herewith |
Furnished Herewith |
|||||||||||||
| 2.1 | Asset Purchase Agreement by and among Louisiana Midstream Gas Services, L.L.C., Chesapeake Midstream Development, L.P. and Magnolia Midstream Gas Services L.L.C., and, for certain limited purposes, Chesapeake Midstream Management, L.L.C., dated as of December 16, 2010 |
8-K | 001-34831 | 2.1 | 12/22/2010 | |||||||||||||||
| 3.1 | Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. |
S-1 | 333-164905 | 3.1 | 02/16/2010 | |||||||||||||||
| 3.2 | First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. dated August 3, 2010. |
8-K | 001-34831 | 3.1 | 08/05/2010 | |||||||||||||||
| 3.3 | Second Amended and Restated Limited Liability Company Agreement of Chesapeake MLP Operating, L.L.C., dated August 3, 2010. |
8-K | 001-34831 | 3.2 | 08/05/2010 | |||||||||||||||
| 10.1 | Underwriting Agreement, dated July 28, 2010, by and among Chesapeake Midstream Partners, L.P., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Ventures, L.L.C., Chesapeake MLP Operating, L.L.C and the Underwriters named therein. |
8-K | 001-34831 | 1.1 | 07/30/2010 | |||||||||||||||
| 10.2 | Contribution, Conveyance and Assumption Agreement by and among Chesapeake Midstream Partners, L.P., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Holdings, L.L.C., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P., Chesapeake Midstream Ventures, L.L.C. and Chesapeake MLP Operating, L.L.C., dated as of July 28, 2010. |
8-K | 001-34831 | 10.1 | 07/30/2010 | |||||||||||||||
| 10.3 | Omnibus Agreement by and among Chesapeake Midstream Holdings, L.L.C., Chesapeake Midstream Ventures, L.L.C. and Chesapeake Midstream Partners, L.P., dated August 3, 2010. |
8-K | 001-34831 | 10.1 | 08/05/2010 | |||||||||||||||
| 10.4 | Amended and Restated Services Agreement by and among Chesapeake Midstream Management, L.L.C., Chesapeake Operating, Inc., Chesapeake Midstream GP, L.L.C, Chesapeake Midstream Partners, L.P. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010. |
8-K | 001-34831 | 10.2 | 08/05/2010 | |||||||||||||||
Table of Contents
| Incorporated by Reference |
||||||||||||||||
| Exhibit |
Exhibit Description |
Form |
SEC File Number |
Exhibit | Filing Date | Filed Herewith |
Furnished Herewith | |||||||||
| 10.5 | Amended and Restated Employee Transfer Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream Management, L.L.C., Chesapeake Midstream GP, L.L.C. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010. |
8-K | 001-34831 | 10.3 | 08/05/2010 | |||||||||||
| 10.6 | Amended and Restated Employee Secondment Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream Management, L.L.C., Chesapeake Midstream GP, L.L.C., Chesapeake Operating, Inc. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010. |
8-K | 001-34831 | 10.4 | 08/05/2010 | |||||||||||
| 10.7 | Amended and Restated Shared Services Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream GP, L.L.C., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010. |
8-K | 001-34831 | 10.5 | 08/05/2010 | |||||||||||
| 10.8 | Registration Rights Agreement by and among Chesapeake Midstream Partners, L.P., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P. and Chesapeake Midstream Holdings, L.L.C., dated August 3, 2010. |
8-K | 001-34831 | 10.6 | 08/05/2010 | |||||||||||
| 10.9 | First Amendment to Credit Agreement among Chesapeake MLP Operating, L.L.C., as the Borrower, Chesapeake Midstream Partners, L.P., as the Parent, Wells Fargo Bank, National Association, as Administrative Agent, The Royal Bank of Scotland plc, as Syndication Agent, Bank of Montreal, Compass Bank and The Bank of Nova Scotia, as Co-Documentation Agents and the other Lenders party thereto, dated as of August 2, 2010. |
8-K | 001-34831 | 10.7 | 08/05/2010 | |||||||||||
| 10.10* | Chesapeake Midstream Long-Term Incentive Plan. |
S-1 | 333-164905 | 10.18 | 07/20/2010 | |||||||||||
| 10.10.1* | Form of Restricted Unit Award Agreement for Long-Term Incentive Plan |
X |
||||||||||||||
| 10.11 | Amended and Restated Gas Gathering Agreement, dated January 25, 2010, by and among Chesapeake Midstream Partners, L.L.C., Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P. and DDJET Limited LLP. |
S-1 | 333-164905 | 10.2 | 07/26/2010 | |||||||||||
Table of Contents
| Incorporated by Reference |
||||||||||||||||||||||||
| Exhibit |
Exhibit Description |
Form |
SEC File Number |
Exhibit | Filing Date | Filed Herewith |
Furnished Herewith |
|||||||||||||||||
| 10.12 | Barnett Gas Gathering Agreement, dated January 25, 2010, by and among Chesapeake Midstream Partners, L.L.C., Total Gas & Power North America, Inc. and Total E&P USA, Inc. |
S-1 | 333-164905 | 10.3 | 07/26/2010 | |||||||||||||||||||
| 10.13† | Gas Gathering Agreement, dated December 21, 2010, by and among Magnolia Midstream Gas Services, L.L.C., Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Empress, L.L.C. and Chesapeake Louisiana L.P. |
X | ||||||||||||||||||||||
| 10.14 | Gas Compressor Master Rental and Servicing Agreement, dated September 30, 2009, between Midcon Compression, LLC and Chesapeake Midstream Partners, L.L.C. |
S-1 | 333-164905 | 10.8 | 04/09/2010 | |||||||||||||||||||
| 10.15† | Amended and Restated Gas Compressor Master Rental and Servicing Agreement, effective as of December 21, 2010, between MidCon Compression, LLC and Chesapeake MLP Operating, L.L.C. |
X | ||||||||||||||||||||||
| 10.16 | Additional Agreement, dated January 25, 2010, by and among Chesapeake Midstream Partners, L.L.C., Total Gas & Power North America, Inc., Total E&P USA, Inc., Chesapeake Energy Marketing, Inc., Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P., DDJET Limited LLP and Chesapeake Operating, Inc. |
S-1 | 333-164905 | 10.4 | 07/26/2010 | |||||||||||||||||||
| 10.17* | Chesapeake Midstream Management Incentive Compensation Plan. |
S-1 | 333-164905 | 10.17 | 07/06/2010 | |||||||||||||||||||
| 10.17.1* | Award Agreement under Chesapeake Midstream Management Incentive Compensation Plan-Robert S. Purgason. |
S-1 | 333-164905 | 10.20 | 07/06/2010 | |||||||||||||||||||
| 10.17.2* | Award Agreement under Chesapeake Midstream Management Incentive Compensation Plan-David C. Shiels. |
S-1 | 333-164905 | 10.21 | 07/06/2010 | |||||||||||||||||||
| 10.18* | Amended and Restated Employment Agreement of J. Mike Stice |
S-1 | 333-164905 | 10.12 | 07/06/2010 | |||||||||||||||||||
| 10.19* | Amendment to Employment Agreement of J. Mike Stice |
S-1 | 333-164905 | 10.13 | 07/06/2010 | |||||||||||||||||||
| 10.20* | Employment Agreement of Robert S. Purgason |
S-1 | 333-164905 | 10.14 | 07/06/2010 | |||||||||||||||||||
| 10.21* | Employment Agreement of David C. Shiels |
S-1 | 333-164905 | 10.15 | 07/06/2010 | |||||||||||||||||||
| 10.22† | Amendment to Amended and Restated Gas Gathering Agreement, dated March 8 2011, by and among Chesapeake Midstream Partners, L.L.C., Chesapeake Energy Marketing, Inc., Chesapeake Operating, Inc., Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P. and DDJET Limited LLP. |
X | ||||||||||||||||||||||
| 21.1 | Subsidiaries of Chesapeake Midstream Partners, L.P. |
X | ||||||||||||||||||||||
Table of Contents
| Incorporated by Reference | ||||||||||||||||
| Exhibit |
Exhibit Description |
Form | SEC File Number |
Exhibit | Filing Date | Filed Herewith |
Furnished Herewith | |||||||||
| 31.1 | J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
X | ||||||||||||||
| 31.2 | David C. Shiels, Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
X | ||||||||||||||
| 32.1 | J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
X | ||||||||||||||
| 32.2 | David C. Shiels, Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
X | ||||||||||||||