10-K 1 d270087d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

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

For the Fiscal Year Ended December 31, 2011

¨    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. 1-13726

 

 

Chesapeake Energy Corporation

(Exact name of registrant as specified in its charter)

 

Oklahoma   73-1395733
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)
6100 North Western Avenue  
Oklahoma City, Oklahoma   73118
(Address of principal executive offices)   (Zip Code)

(405) 848-8000

(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 Stock, par value $0.01

      New York Stock Exchange

7.625% Senior Notes due 2013

      New York Stock Exchange

9.5% Senior Notes due 2015

      New York Stock Exchange

6.25% Senior Notes due 2017

      New York Stock Exchange

6.5% Senior Notes due 2017

      New York Stock Exchange

6.875% Senior Notes due 2018

      New York Stock Exchange

7.25% Senior Notes due 2018

      New York Stock Exchange

6.775% Senior Notes due 2019

      New York Stock Exchange

6.625% Senior Notes due 2020

      New York Stock Exchange

6.875% Senior Notes due 2020

      New York Stock Exchange

6.125% Senior Notes due 2021

      New York Stock Exchange

2.75% Contingent Convertible Senior Notes due 2035

      New York Stock Exchange

2.5% Contingent Convertible Senior Notes due 2037

      New York Stock Exchange

2.25% Contingent Convertible Senior Notes due 2038

      New York Stock Exchange

4.5% Cumulative Convertible Preferred Stock

      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  x    NO  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  YES  ¨    NO  x

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

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

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

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

 

Large Accelerated Filer  x

   Accelerated Filer  ¨   

Non-accelerated Filer  ¨

  

Smaller Reporting Company  ¨

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

The aggregate market value of our common stock held by non-affiliates on June 30, 2011 was approximately $19.4 billion. At February 22, 2012, there were 662,498,825 shares of our $0.01 par value common stock outstanding.

 

 

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the 2012 Annual Meeting of Shareholders are incorporated by reference in Part III.

 

 

 


Table of Contents

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

2011 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

 

PART I    Page  

Item 1.

  

Business

     2   

Item 1A.

  

Risk Factors

     34   

Item 1B.

  

Unresolved Staff Comments

     43   

Item 2.

  

Properties

     43   

Item 3.

  

Legal Proceedings

     43   

Item 4.

  

Mine Safety Disclosures

     46   
PART II   

Item 5.

  

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     47   

Item 6.

  

Selected Financial Data

     49   

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     51   

Item 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

     87   

Item 8.

  

Financial Statements and Supplementary Data

     95   

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     187   

Item 9A.

  

Controls and Procedures

     187   

Item 9B.

  

Other Information

     187   
PART III   

Item 10.

  

Directors, Executive Officers and Corporate Governance

     188   

Item 11.

  

Executive Compensation

     188   

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     188   

Item 13.

  

Certain Relationships and Related Transactions and Director Independence

     188   

Item 14.

  

Principal Accountant Fees and Services

     188   
PART IV   

Item 15.

  

Exhibits and Financial Statement Schedules

     189   

 


Table of Contents

Part I

 

ITEM 1. Business

Our Business

We are the second-largest producer of natural gas, a top 15 producer of oil and natural gas liquids (collectively “liquids”) and the most active driller of new wells in the U.S. We own interests in approximately 45,700 producing natural gas and oil wells that are currently producing approximately 3.5 billion cubic feet of natural gas equivalent (bcfe) per day, net to our interest. Our business strategy is focused on discovering and developing large accumulations of natural gas resources in the Haynesville and Bossier Shales in northwestern Louisiana and East Texas; the Marcellus Shale in the northern Appalachian Basin of West Virginia and Pennsylvania; the Barnett Shale in the Fort Worth Basin of north-central Texas; and the Pearsall Shale in South Texas. In addition, we have built leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas; the Utica Shale in Ohio and Pennsylvania; the Granite Wash, Cleveland, Tonkawa and Mississippi Lime plays in the Anadarko Basin in western Oklahoma and the Texas Panhandle; the Bone Spring, Avalon, Wolfcamp and Wolfberry plays in the Permian and Delaware Basins in West Texas and southern New Mexico; and the Niobrara Shale in the Powder River Basin in Wyoming.

We have also vertically integrated many of our operations and own substantial marketing, compression, midstream and oilfield services businesses. Our marketing business is named Chesapeake Energy Marketing, Inc. (CEMI) and is a top 10 marketer of natural gas in the U.S. and one of the largest liquids marketers as well. Our compression business is conducted under MidCon Compression, L.L.C. (MidCon) and its assets include over 1.0 million horsepower of compression, making MidCon the second largest compression company in the U.S. Our midstream operations consist of wholly owned Chesapeake Midstream Development, L.P. (CMD) and a 46% investment in Chesapeake Midstream Partners, L.P. (NYSE: CHKM). Our oilfield services business is conducted under the name Chesapeake Oilfield Services, L.L.C. (COS) and its primary operating subsidiaries include Nomac Drilling, L.L.C., the nation’s fourth largest drilling contractor, Thunder Oilfield Services L.L.C., which owns one of the largest oilfield trucking and oilfield equipment rental businesses, and Performance Technologies, L.L.C., our pressure pumping business, which we believe will become one of the nation’s five largest pressure pumping businesses in the next few years. Our ownership of these marketing, compression, midstream and oilfield service businesses improves our efficiency, scale, safety and profitability.

We have been developing expertise in horizontal drilling technology since shortly after our formation in 1989 and focused almost exclusively on developing natural gas properties in the U.S. from 2000 to 2008. We were one of the first companies to recognize the potential of horizontal drilling in unconventional natural gas reservoirs, especially shales, in the U.S. during the early part of the prior decade. During the past 10 years, we have grown from the 12th largest natural gas producer in the U.S. to the second-largest natural gas producer, in large part as a result of our success in finding and developing unconventional natural gas assets.

In recognition of the value gap between oil and natural gas prices that has widened to historic levels in the last three years, Chesapeake has directed a significant portion of its technological and leasehold acquisition expertise to identify, secure and commercialize new unconventional liquids-rich plays. This planned transition will result in a more balanced and likely more profitable portfolio between natural gas and liquids. To date, we have built leasehold positions and established production in multiple liquids-rich plays on approximately 6.6 million net acres. Our production of liquids averaged approximately 86,800 barrels (bbls) per day during 2011, a 72% increase over the average during 2010, as a result of the increased development of our unconventional liquids-rich plays. In 2011, approximately 50% of our drilling and completion expenditures were allocated to liquids-rich plays, compared to 30% in 2010 and 10% in 2009. We are projecting that the portion of our operated drilling

 

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and completion expenditures allocated to liquids development will reach 85% in 2012, and we expect to increase our liquids production through our drilling activities to an average of approximately 150,000 bbls per day in 2012 and to more than 200,000 bbls per day in 2013 and 250,000 bbls per day by 2015.

During 2011, our estimated proved reserves grew from 17.096 trillion cubic feet of natural gas equivalent (tcfe) to 18.789 tcfe, 54% of which was proved developed and 100% was onshore in the U.S. We replaced our 1.194 tcfe of 2011 production with an estimated 2.887 tcfe of new proved reserves for a reserve replacement rate of 242%. The 2011 proved reserve movement included 5.683 tcfe of extensions, 64 bcfe of negative performance revisions to previous estimates and 14 bcfe of positive revisions resulting from higher oil prices using the average first-day-of-the-month price for the twelve months ended December 31, 2011, compared to the twelve months ended December 31, 2010. During 2011, we acquired 30 bcfe of estimated proved reserves and divested 2.776 tcfe of estimated proved reserves, including the disposition of 2.420 tcfe associated with the sale of our Fayetteville Shale assets for $4.65 billion in March 2011. The 64 bcfe of negative revisions to previous estimates consisted of 337 bcfe of negative revisions associated with the deletion of proved undeveloped reserves no longer consistent with our development plans, offset by 273 bcfe of positive revisions to producing properties and proved undeveloped reserves estimates.

Daily production for 2011 averaged 3.272 bcfe, an increase of 436 million cubic feet of natural gas equivalent (mmcfe), or 15%, over the 2.836 bcfe of daily production for 2010 and consisted of 2.751 billion cubic feet of natural gas (bcf) (84% on a natural gas equivalent basis) and 86,784 bbls of liquids (16% on a natural gas equivalent basis). Our natural gas production in 2011 grew by 9%, or 217 mmcf per day, and our liquids production increased by 72%, or 36,386 bbls per day. This was our 22nd consecutive year of sequential production growth.

Information About Us

Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118 and our main telephone number at that location is (405) 848-8000. We make available free of charge on our website at www.chk.com our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. References to “Chesapeake”, the “Company”, “us”, “we” and “our” in this report are to Chesapeake Energy Corporation together with its subsidiaries, unless the context otherwise requires.

Recent Developments

Update to Operating Plan in Response to Low Natural Gas Prices

On February 13, 2012, in response to the lowest natural gas prices the U.S. has experienced in the past 10 years, we announced that we have taken a series of steps outlined below.

First, we are reducing our operated dry gas drilling activity to approximately 24 rigs by the second quarter of 2012 from 47 dry gas rigs in use in January 2012 and from an average of 75 dry gas rigs used during 2011. Our operated dry gas drilling and completion expenditures in 2012, net of drilling carries, are expected to decrease to $900 million, or approximately 70%, from similar expenditures of $3.1 billion in 2011.

Second, we have curtailed approximately 1.0 bcf per day of gross operated natural gas production, or approximately 1.5% of U.S. lower 48 natural gas production. The curtailed volumes are located primarily in the Haynesville and Barnett Shale plays and have been implemented to minimize

 

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the impact of existing midstream and transportation commitments. In addition, wherever possible, we are deferring completions of dry gas wells that have been drilled but not yet completed, and we are also deferring pipeline connections to dry gas wells that have already been completed.

Third, we have reallocated capital from reduced dry gas drilling, well completion and pipeline connection activities to our liquids-rich plays that offer superior returns in the current strong liquids price environment. This reallocation will result in increased expenditures in certain of our liquids-rich plays, including the Eagle Ford Shale, Utica Shale, Mississippi Lime, Granite Wash, Cleveland, Tonkawa, Niobrara, Bone Spring, Avalon, Wolfcamp and Wolfberry plays. We estimate that approximately 85% of our 2012 total net operated drilling and completion expenditures will be invested in our liquids-rich plays.

Fourth, we plan to further reduce our undeveloped leasehold expenditures, the majority of which have been focused on acquiring leading positions in liquids-rich plays during the past three years. We are now targeting to invest approximately $1.4 billion in undeveloped leasehold expenditures in 2012, net of ongoing joint venture reimbursements, of which approximately 90% will be in liquids-rich plays and 100% will be in plays where we are already active. This compares to undeveloped leasehold expenditures of approximately $3.5 billion and $5.8 billion in 2011 and 2010, respectively.

Update to Financial Plan

Our business strategy is to continue our reserves and production growth and transition to increased liquids production. As a result of this strategy, we plan to make capital expenditures in 2012 that will exceed our projected cash flow from operations. We plan to obtain funds for these capital expenditures from operating cash flow, supplemented by various asset monetization transactions, including joint ventures, volumetric production payments, financial transactions and other property and investment dispositions.

We recently announced that we are pursuing a volumetric production payment transaction in our Texas Panhandle Granite Wash play and a financial transaction in our Cleveland and Tonkawa plays (similar to our recent CHK Utica financial transaction), and we are targeting to close each of these transactions by the end of the 2012 first quarter. Additionally, we are pursuing a joint venture transaction in our Mississippi Lime play in northern Oklahoma and southern Kansas, where we own approximately 1.8 million net acres today and expect to own approximately 2.0 million net acres at the time of the joint venture closing, and in the Permian Basin in West Texas and southern New Mexico, where we own approximately 1.5 million net acres. We may also consider the sale of all of our interests in the Permian Basin. Our Permian Basin assets represent approximately 5% of the Company’s total proved reserves and current net production. We are targeting completion of the Mississippi Lime and Permian Basin transactions by the end of the 2012 third quarter. Finally, we plan to continue to seek monetizations of a portion of our midstream assets, our oilfield services assets and other miscellaneous investments. While we expect that the proceeds from these transactions will be sufficient to fund our planned capital expenditures, we do not have binding agreements for any of these transactions and our ability to consummate each of these transactions is subject to changes in market conditions and other factors. As a result, there can be no assurance that we will complete any of these transactions on a timely basis or at all. To the extent that proceeds from these potential transactions are inadequate to fund our planned spending, we would be required to modify our drilling program or monetize different or additional assets.

Update to 25/25 Plan

Our 25/25 Plan calls for our long-term debt to be no more than $9.5 billion as of December 31, 2012 and for us to increase our production by 25% during the two-year period ended December 31, 2012. Our long-term debt (net of cash) as of December 31, 2011 was approximately $10.3 billion, a reduction of $2.2 billion from the year-end 2010 level of $12.5 billion. We plan to reduce our indebtedness to no more than our stated goal of $9.5 billion by year-end 2012 primarily with the proceeds from the asset monetization transactions described above.

 

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Business Strategy

Since our inception in 1989, Chesapeake’s primary goal has been to create value for investors by building and developing one of the largest onshore natural gas and liquids-rich resource bases in the U.S. Key elements of this business strategy are further explained below.

Grow Through the Drillbit. We believe that our most distinctive characteristic is our commitment and ability to grow production and proved reserves organically through the drillbit at low cost in areas with large unconventional accumulations of natural gas and liquids. We are currently utilizing 161 operated drilling rigs and 100 non-operated drilling rigs to conduct the most active drilling program in the U.S. We are active in most of the nation’s major unconventional plays, where we drill more horizontal wells than any other company in the industry. For many years, we have been actively investing large amounts of capital in undeveloped leasehold, three dimensional (3-D) seismic information and human resources to take full advantage of our capacity to grow through the drillbit. We are one of the few large-cap independent natural gas and oil companies that have been able to consistently increase production, which we have successfully achieved for 22 consecutive years. We believe the key elements of the success and scale of our drilling program have been our recognition, earlier than most of our competitors, that advanced horizontal drilling and completion techniques would enable development of previously uneconomic natural gas and liquids-rich reservoirs and that, as a consequence, various unconventional formations could be recognized and developed as potentially prolific reservoirs. In response to our early recognition of these trends, we have proactively hired thousands of new employees and have built the largest combined inventory of onshore leasehold and 3-D seismic in the U.S. These are the building blocks of our successful large-scale drilling program and the foundation of value creation for our company.

Control Substantial Land and Drilling Location Inventories. After we identified the trends discussed above, we initiated a plan to build and maintain the largest inventory of onshore drilling opportunities in the U.S. Recognizing that better horizontal drilling and completion technologies, when applied to various new unconventional reservoirs, would likely create a unique opportunity to capture decades worth of drilling opportunities, we embarked on an aggressive lease acquisition program, which we have referred to as the “gas shale land grab” of 2006 through 2008 and the “unconventional oil land grab” of 2009 through 2011. We believed that the winner of these land grabs would enjoy competitive advantages for decades to come as other companies would be locked out of the best new unconventional resource plays in the U.S. We believe that we have executed our land acquisition strategy with particular distinction. At December 31, 2011, we held approximately 15.3 million net acres of onshore leasehold in the U.S. and have identified approximately 39,200 drilling opportunities on this leasehold. We believe this extensive backlog of drilling, approximately 20 years worth at current drilling levels, provides strong evidence of our future growth capabilities. We further believe that our U.S.-based undeveloped leasehold acquisition phase is now substantially complete. We spent significantly less on new leasehold in 2011 than in 2010 and are forecasting even lower undeveloped leasehold acquisition expenditures in 2012.

Build Operating Focus and Scale. We believe one of the keys to success in the U.S. exploration and production industry is to build significant operating scale in areas that share many similar geological and operational characteristics. Achieving such scale provides many benefits, including superior geoscientific and engineering information, higher per unit revenues, lower per unit operating expenses, greater rates of drilling success, higher returns from more easily integrated acquisitions and higher returns on drilling investments. By focusing most of our future activities in virtually all of the nation’s major unconventional resource plays and not investing offshore and internationally, we expect to continue to achieve the significant benefits of focus and scale.

Develop Proprietary Technological Advantages. In addition to our industry-leading undeveloped leasehold position, we have developed a number of proprietary technological advantages. First, we have acquired the nation’s largest inventory of 3-D seismic information. Possessing this 3-D seismic

 

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data enables us to image reservoirs of natural gas and liquids that might otherwise remain undiscovered and to drill our horizontal wells more accurately inside the targeted formation and avoid various underground geohazards such as faults and karsts. In addition, we have developed an industry-leading information-gathering program that gives us unequalled insight into new plays and competitor activity. As a result of our initiatives, we now produce approximately 9% of the nation’s natural gas, drill approximately 8% of its wells and participate in almost an equal number of wells drilled by others. By gathering this information on a real-time basis, then quickly assimilating and analyzing the information, we are able to react quickly to opportunities that are created through our drilling program and those of our competitors. Furthermore, we have established a unique state-of-the-art Reservoir Technology Center (RTC) in Oklahoma City. The RTC enables us to more quickly, accurately and confidentially analyze core data from wells drilled through unconventional formations on a proprietary basis, then identify new plays and leasing opportunities ahead of our competition and reduce the likelihood of investing in plays that ultimately are not commercial. It also allows us to design fracture stimulation procedures that might work most productively in the unconventional formations we target.

Focus on Low Costs and Vertical Integration. By minimizing lease operating expenses and general and administrative expenses through focused activities, vertical integration and increasing scale, we have been able to deliver attractive profit margins and financial returns through all phases of the commodity price cycle. We believe our low cost structure is the result of management’s effective cost-control programs, a high-quality asset base and extensive access to oilfield services, especially our own through COS, and natural gas processing and transportation infrastructures that exist in our key operating areas. Our high level of drilling activity and production volumes will create considerable value for the providers of oilfield services and compression and midstream gathering services. Our strategy is to capture a portion of this value for our shareholders rather than transfer it to third-party vendors. As of December 31, 2011, we operated approximately 24,800 of our 45,700 wells, which delivered approximately 85% of our daily production volume. This large percentage of operated properties provides us with a high degree of operational flexibility and cost control.

Mitigate Natural Gas and Oil Price Risk. We have used and intend to continue using our hedging program to mitigate the risks inherent in developing and producing natural gas and liquids-rich resources, that are often subject to significant price volatility. We intend to use this volatility to our benefit by taking advantage of prices when they reach levels that management believes are either unsustainable for the long term or provide unusually high rates of return on our invested capital.

Form Value-Creating Joint Ventures. As of December 31, 2011, we had entered into seven significant joint ventures with other leading energy companies pursuant to which we sold a minority interest in our leasehold, producing properties and other assets located in seven different resource plays and received cash of $7.1 billion and commitments for future drilling and completion cost sharing of $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all

 

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leasing, drilling, completion, operations and marketing activities for the project. These transactions have allowed us to recover much or all of our initial leasehold investments and reduce our ongoing capital costs in these plays. The transactions are detailed below.

 

Primary

Play

  Joint
Venture
Partner(a)
 

Joint
Venture
Date

  Interest
Sold
   Cash
Proceeds
Received
at Closing
    Total
Drilling
Carries
    Drilling
Carries
Remaining(b)
 
                 ($ in millions)  

Utica

 

TOT

 

December 2011

  25.0%    $ 610      $ 1,422      $ 1,422   

Niobrara

 

CNOOC

 

February 2011

  33.3%      570        697        570   

Eagle Ford & Pearsall

 

CNOOC

 

November 2010

  33.3%      1,120        1,080        144   

Barnett

 

TOT

 

January 2010

  25.0%      800            1,404 (c)        

Marcellus

 

STO

 

November 2008

  32.5%      1,250        2,125        223   

Fayetteville

 

BP

 

September 2008

  25.0%      1,100        800          

Haynesville & Bossier

 

PXP

 

July 2008

  20.0%      1,650        1,508 (d)        
        

 

 

   

 

 

   

 

 

 
         $ 7,100      $ 9,036      $ 2,359   
        

 

 

   

 

 

   

 

 

 

 

(a)

Joint venture partners include Total S.A. (TOT), CNOOC Limited (CNOOC), Statoil (STO), BP America (BP) and Plains Exploration & Production Company (PXP).

 

(b)

As of December 31, 2011.

 

(c)

In conjunction with an agreement requiring us to maintain our operated rig count at no less than 12 rigs in the Barnett Shale through December 31, 2012, TOT accelerated the payment of its remaining joint venture drilling carry in exchange for an approximate 9% reduction in the total amount of drilling carry obligation owed to us at that time. As a result, in October 2011, we received $471 million in cash from TOT, which included $46 million of carry obligation billed and $425 million for the remaining carry obligation. In January 2012, Chesapeake and TOT agreed to reduce the minimum rig count from 12 to six rigs.

 

(d)

In September 2009, PXP accelerated the payment of its remaining carry in exchange for an approximate 12% reduction to the remaining drilling carry obligation owed to us at that time.

Improve Our Balance Sheet through Reduction of Debt. Our 2011 – 2012 strategic and financial plan calls for a 25% reduction in our long-term debt while growing net natural gas and liquids production by 25% by the end of 2012. We believe this reduction of our debt and continued growth in our asset base will lead to our long-term debt to reserves ratio (long-term debt net of cash divided by our estimated proved reserves) decreasing to less than $0.50 per mcfe at year-end 2012 compared to $0.55 per mcfe at year-end 2011 and $0.73 per mcfe at year-end 2010. We expect to achieve our goal of reducing debt primarily with proceeds from asset monetizations during this two-year period. Among the several benefits of lower debt are lower borrowing costs, and we believe improved credit metrics will lead to more favorable debt ratings by the major ratings agencies over time.

Transform U.S. Transportation Fuels Market and Increase Demand for U.S. Natural Gas. In an effort to decrease U.S. dependence on foreign oil imports and increase demand for U.S. natural gas, in July 2011, we announced our plan to create Chesapeake NG Ventures Corporation (CNGV), which is dedicated to identifying and investing in companies and technologies that have the potential to replace the use of gasoline and diesel derived primarily from imported oil with domestic oil, natural gas and natural gas-to-liquids fuels. We believe this plan, if successful, will benefit our industry and will also lower energy costs to American consumers, enhance national security, stimulate economic growth, create new high-paying jobs and improve the environment. To fund our commitment, we intend to redirect approximately 1 – 2% of our forecasted annual drilling and completion budget away from efforts to increase natural gas supply toward projects that instead are designed to stimulate natural gas

 

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demand. Over a 10-year period, we anticipate investing at least $1.0 billion in CNGV initiatives seeking breakthroughs in scalable, natural gas-focused technologies. To date, we have committed approximately $315 million in total to three separate ventures. In 2011, we agreed to invest $150 million in newly issued convertible promissory notes of Clean Energy Fuels Corp. (Nasdaq:CLNE), based in Seal Beach, California, to help CLNE accelerate the build-out of LNG fueling infrastructure for heavy-duty trucks at truck stops across interstate highways in the U.S. Also in 2011, we agreed to invest $155 million in preferred equity securities of Sundrop Fuels, Inc., a privately held cellulosic biofuels company based in Louisville, Colorado to fund construction of a waste biomass-based “green gasoline” plant, capable of annually producing more than 40 million gallons of gasoline from natural gas and cellulosic material. More recently, in 2012, we pledged an initial $10 million towards a collaboration with 3M (NYSE:MMM) to design, manufacture and market a broad portfolio of compressed natural gas tanks for use in all sectors of the U.S. transportation market.

Maintain an Entrepreneurial Culture. Chesapeake was formed in 1989 with an initial capitalization of $50,000 and fewer than ten employees. We completed our initial public offering of common stock in early 1993 and subsequent to those early corporate milestones, our management team has guided the Company through various operational and industry challenges and opportunities and extremes of natural gas and oil prices to create the nation’s second-largest producer of natural gas, a top 15 producer of liquids, the most active driller of new wells in the U.S., a major oilfield services provider, one of the nation’s largest midstream and natural gas and liquids marketing companies, an employer of approximately 12,600 people and an indirect employer of tens of thousands more. We take pride in our innovative and aggressive implementation of our business strategy and strive to be as entrepreneurial today as we were when we were a much smaller company. We have maintained an unusually flat organizational structure as we have grown to help ensure that important information travels rapidly through the Company and decisions are made and implemented quickly. Our efforts in the development of our human resources have been recognized by many, most recently Fortune Magazine, which in January 2012 named Chesapeake the 18th best company to work for in the U.S., including the fifth-best among U.S. companies with more than 10,000 employees and the top-ranked company within the U.S. oil and gas industry.

Operating Divisions

Chesapeake focuses its exploration, development, acquisition and production efforts in four geographic operating divisions described below.

Southern Division. Our Southern division primarily includes the Haynesville and Bossier Shales in northwestern Louisiana and East Texas and the Barnett Shale in the Fort Worth Basin of north-central Texas. Proved reserves in the Southern division were 8.039 tcfe, or 43%, of our total proved reserves by volume as of December 31, 2011. During 2011, the Southern division assets produced 562 bcfe, or 47%, of our total 2011 production, and we invested approximately $2.7 billion to drill 1,104 gross (550 net) wells, net of $417 million in drilling and completion cost carries paid by our Barnett Shale joint venture partner, Total. For 2012, we anticipate spending approximately $700 million, or 10% of our total budget, for exploration and development activities in the Southern division.

Northern Division. Our Northern division includes the Mid-Continent (principally the Anadarko Basin in western Oklahoma and the Texas Panhandle) and, prior to April 2011, the Fayetteville Shale. In March 2011, we sold all of our Fayetteville Shale assets. Proved reserves in the Northern division were 5.416 tcfe, or 29%, of our total proved reserves by volume as of December 31, 2011. During 2011, the Northern division assets produced 383 bcfe, or 32%, of our total 2011 production, and we invested approximately $1.8 billion to drill 1,076 gross (342 net) wells. For 2012, we anticipate spending approximately $2.6 billion, or 36% of our total budget for exploration and development activities in the Northern division, with a continuing focus on the Granite Wash and an increasing focus on the Tonkawa, Cleveland and Mississippi Lime liquids-rich unconventional plays in the Anadarko Basin.

 

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Eastern Division. Our Eastern division primarily includes the Marcellus Shale in the northern Appalachian Basin of West Virginia and Pennsylvania and the Utica Shale in Ohio and Pennsylvania. Proved reserves in the Eastern division were 3.188 tcfe, or 17%, of our total proved reserves by volume as of December 31, 2011. During 2011, the Eastern division assets produced 145 bcfe, or 12%, of our total 2011 production, and we invested approximately $1.5 billion to drill 371 gross (149 net) wells, net of $1.1 billion in drilling and completion cost carries paid by our Marcellus Shale joint partner, Statoil. For 2012, we anticipate spending approximately $1.2 billion, or 17% of our total budget, net of carries, for exploration and development activities in the Eastern division. Statoil will pay 75% of our drilling and completion costs in the Marcellus Shale until $2.125 billion has been paid. We expect all of the $223 million drilling and completion cost carry remaining in the Marcellus Shale as of December 31, 2011 will be utilized in 2012. Total, our Utica Shale joint venture partner, will pay 60% of our drilling and completion costs in the play until $1.422 billion has been paid, which we expect to occur by year-end 2018. Of the $1.422 billion of drilling and completion cost carry remaining as of December 31, 2011, we expect approximately $350 million will be utilized in 2012.

Western Division. Our Western division primarily includes the Permian and Delaware Basins of West Texas and southern New Mexico, the Eagle Ford Shale in South Texas and the Rocky Mountain/Williston Basin plays, including the Niobrara Shale. Proved reserves in the Western division were 2.146 tcfe, or 11%, of our total proved reserves by volume as of December 31, 2011. During 2011, the Western division assets produced 105 bcfe, or 9%, of our total 2011 production, and we invested approximately $1.7 billion to drill 428 gross (241 net) wells, net of $1.0 billion in drilling and completion cost carries paid by our joint venture partner in the Eagle Ford Shale and the Niobrara Shale, CNOOC. For 2012, we anticipate spending approximately $2.7 billion, or 37% of our total budget, net of carries, for exploration and development activities in the Western division, with an increased focus on the Bone Spring, Avalon, Wolfcamp and Wolfberry liquids-rich unconventional plays located in the Permian and Delaware Basins. CNOOC will pay 75% of our drilling and completion costs in the Eagle Ford Shale until $1.08 billion has been paid. We expect all of the $144 million drilling cost carry remaining in the Eagle Ford Shale as of December 31, 2011 will be utilized in the 2012 first quarter. CNOOC will also pay approximately 67% of our drilling and completion costs in the Niobrara Shale until $697 million has been paid, which we expect to occur by year-end 2014. Of the $570 million of drilling and completion cost carry remaining in the Niobrara Shale, we expect approximately $125 million will be utilized in 2012.

Well Data

At December 31, 2011, we had interests in approximately 45,700 gross (22,000 net) productive wells, including properties in which we held an overriding royalty interest, of which 38,000 gross (19,600 net) were classified as primarily natural gas productive wells and 7,700 gross (2,400 net) were classified as primarily oil productive wells. Chesapeake operates approximately 24,800 of its 45,700 productive wells. During 2011, we drilled 1,628 gross (1,069 net) wells and participated in another 1,351 gross (213 net) wells operated by other companies. We operate approximately 85% of our current daily production volumes.

 

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Drilling Activity

The following table sets forth the wells we drilled or participated in during the periods indicated. In the table, “gross” refers to the total wells in which we had a working interest and “net” refers to gross wells multiplied by our working interest.

 

    2011     2010     2009  
    Gross     %     Net     %     Gross     %     Net     %     Gross     %     Net     %  

Development:

                       

Productive

    2,536        99        1,077        99        2,721        99        1,031        99        1,971        98        875        99   

Dry

    10        1        3        1        30        1        12        1        33        2        8        1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    2,546        100     1,080        100     2,751        100     1,043        100     2,004        100     883        100
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Exploratory:

                       

Productive

    430        99        201        99        265        95        99        93        196        97        115        96   

Dry

    3        1        1        1        15        5        7        7        6        3        5        4   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    433        100     202        100     280        100     106        100     202        100     120        100
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The following table shows the wells we drilled or participated in by operating division:

 

     2011      2010      2009  
     Gross
Wells
     Net
Wells
     Gross
Wells
     Net
Wells
     Gross
Wells
     Net
Wells
 

Southern

     1,104         550         1,023         495         795         527   

Northern

     1,076         342         1,371         369         1,160         353   

Eastern

     371         149         367         140         158         81   

Western

     428         241         270         145         93         42   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

         2,979             1,282             3,031             1,149             2,206             1,003   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

At December 31, 2011, we had 1,282 (537 net) wells in drilling or completing status or waiting on pipe.

 

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Production, Sales, Prices and Expenses

The following table sets forth information regarding the production volumes, natural gas and oil sales, average sales prices received, other operating income and expenses for the periods indicated:

 

     Years Ended December 31,  
         2011             2010             2009      

Net Production(a):

      

Natural gas (bcf)

     1,004.1        924.9        834.8   

Oil (mmbbl)(b)

     31.7        18.4        11.8   

Natural gas equivalent (bcfe)(c )

     1,194.2        1,035.2        905.5   

Natural Gas and Oil Sales ($ in millions):

      

Natural gas sales

   $ 3,133      $ 3,169      $ 2,635   

Natural gas derivatives – realized gains (losses)

     1,656        1,982        2,313   

Natural gas derivatives – unrealized gains (losses)

     (669     425        (492
  

 

 

   

 

 

   

 

 

 

Total natural gas sales

     4,120        5,576        4,456   
  

 

 

   

 

 

   

 

 

 

Oil sales(b)

     2,126        1,079        656   

Oil derivatives – realized gains (losses)

     (102     74        33   

Oil derivatives – unrealized gains (losses)

     (120     (1,082     (96
  

 

 

   

 

 

   

 

 

 

Total oil sales

     1,904        71        593   
  

 

 

   

 

 

   

 

 

 

Total natural gas and oil sales

   $ 6,024      $ 5,647      $ 5,049   
  

 

 

   

 

 

   

 

 

 

Average Sales Price (excluding gains (losses) on derivatives)(a):

      

Natural gas ($ per mcf)

   $ 3.12      $ 3.43      $ 3.16   

Oil ($ per bbl)(b)

   $ 67.11      $ 58.67      $ 55.60   

Natural gas equivalent ($ per mcfe)

   $ 4.40      $ 4.10      $ 3.63   

Average Sales Price (excluding unrealized gains (losses) on derivatives):

      

Natural gas ($ per mcf)

   $ 4.77      $ 5.57      $ 5.93   

Oil ($ per bbl)(b)

   $ 63.90      $ 62.71      $ 58.38   

Natural gas equivalent ($ per mcfe)

   $ 5.70      $ 6.09      $ 6.22   

Other Operating Income(d) ($ per mcfe):

      

Marketing, gathering and compression net margin

   $ 0.10      $ 0.12      $ 0.16   

Oilfield services net margin

   $ 0.10      $ 0.03      $ 0.01   

Expenses ($ per mcfe):

      

Production expenses(a)

   $ 0.90      $ 0.86      $ 0.97   

Production taxes

   $ 0.16      $ 0.15      $ 0.12   

General and administrative expenses

   $ 0.46      $ 0.44      $ 0.38   

Natural gas and oil depreciation, depletion and amortization

   $ 1.37      $ 1.35      $ 1.51   

Depreciation and amortization of other assets

   $ 0.24      $ 0.21      $ 0.27   

Interest expense(e)

   $ 0.03      $ 0.08      $ 0.22   

 

(a)

Our production, prices and production expenses are disclosed by division under Results of Operations in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

(b)

Includes natural gas liquids (NGLs).

 

(c)

Natural gas equivalent is based on six mcf of natural gas to one barrel of oil. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given recent commodity prices, the price for an mcfe of natural gas is significantly less than the price for an mcfe of oil or NGLs.

 

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(d)

Includes revenue and operating costs and excludes depreciation and amortization of other assets.

 

(e)

Includes the effects of realized (gains) losses from interest rate derivatives, but excludes the effects of unrealized (gains) losses and is net of amounts capitalized.

Natural Gas and Oil Reserves

The tables below set forth information as of December 31, 2011 with respect to our estimated proved reserves, the associated estimated future net revenue and present value (discounted at an annual rate of 10%) of estimated future net revenue before and after future income taxes (standardized measure) at such date. Neither the pre-tax present value of estimated future net revenue nor the after-tax standardized measure is intended to represent the current market value of the estimated natural gas and oil reserves we own. All of our estimated natural gas and oil reserves are located within the U.S.

 

     December 31, 2011  
     Natural Gas
(bcf)
     Oil
(mmbbl)(a)
     Total
    (bcfe)(b)    
 

Proved developed

     8,578         254.6         10,106   

Proved undeveloped

     6,937         290.9         8,683   
  

 

 

    

 

 

    

 

 

 

Total proved(c)

     15,515         545.5         18,789   
  

 

 

    

 

 

    

 

 

 
     Proved
Developed
     Proved
Undeveloped
     Total
Proved
 
     ($ in millions)  

Estimated future net revenue(d )

   $ 27,895       $ 20,149       $ 48,044   

Present value of estimated future net revenue(d )

   $ 14,039       $ 5,839       $ 19,878   

Standardized measure(d)( e)

         $ 15,630   

 

     Natural
Gas
(bcf)
     Oil
(mmbbl)(a)
     Natural
Gas
Equivalent
(bcfe)(b)
     Percent of
Proved
Reserves
    Present
Value
($ millions)
 

Southern

     7,928         18.3         8,039         43       $ 3,898   

Northern

     3,510         317.7         5,416         29        8,568   

Eastern

     3,053         22.5         3,188         17        3,669   

Western

     1,024         187.0         2,146         11        3,743   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total

         15,515             545.5             18,789             100       $ 19,878 (d) 
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

(a)

Includes NGLs.

 

(b)

Natural gas equivalent based on six mcf of natural gas to one barrel of oil.

 

(c)

Includes 130 bcf of natural gas and 18.9 mmbbls oil reserves owned by the Chesapeake Granite Wash Trust, 64 bcf and 9.3 mmbbls of which are attributable to the noncontrolling interest holders.

 

(d)

Estimated future net revenue represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2011. For the purpose of determining “prices”, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2011. The prices used in our reserve reports were $4.12 per mcf of natural gas and $95.97 per barrel of oil, before price differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2011. The amounts shown do not give effect to non-property related expenses, such as corporate

 

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general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue differs from the standardized measure only because the former does not include the effects of estimated future income tax expenses ($4.2 billion as of December 31, 2011).

 

    

Management uses future net revenue, which is calculated without deducting estimated future income tax expenses, and the present value thereof, as one measure of the value of the Company’s current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While future net revenue and present value are based on prices, costs and discount factors which are consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company.

 

(e)

Additional information on the standardized measure is presented in Note 10 of the notes to our consolidated financial statements included in Item 8 of this report.

As of December 31, 2011, our reserve estimates included 8.683 tcfe of reserves classified as proved undeveloped (PUD), compared to 7.953 tcfe as of December 31, 2010. Presented below is a summary of changes in our proved undeveloped reserves for 2011.

 

     Total
    (bcfe)    
 

Proved undeveloped reserves, beginning of period

     7,953   

Extensions, discoveries and other additions

     3,564   

Revisions of previous estimates

     (397

Developed

     (1,076

Sale of reserves-in-place

     (1,375

Purchase of reserves-in-place

     14   
  

 

 

 

Proved undeveloped reserves, end of period

     8,683   
  

 

 

 

As of December 31, 2011, there were no PUDs that had remained undeveloped for five years or more. We invested approximately $1.477 billion, net of drilling and completion cost carries, in 2011 to convert 1.076 tcfe of PUDs to proved developed reserves. In 2012, we estimate that we will invest approximately $2.3 billion, net of drilling and completion cost carries, for PUD conversion.

The future net revenue attributable to our estimated proved undeveloped reserves of $20.149 billion at December 31, 2011, and the $5.839 billion present value thereof, has been calculated assuming that we will expend approximately $13.6 billion to develop these reserves: $2.3 billion in 2012, $2.5 billion in 2013, $3.3 billion in 2014 and $5.5 billion in 2015 and beyond, although the amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs, commodity prices and the availability of capital. Chesapeake’s developmental drilling schedules are subject to revision and reprioritization throughout the year resulting from unknowable factors such as the relative success in an individual developmental drilling prospect leading to an additional drilling opportunity, rig availability, title issues or delays, and the effect that acquisitions may have on prioritizing developmental drilling plans.

The SEC’s modernized rules for reporting oil and gas reserves, which became effective December 31, 2009, allow the booking of proved undeveloped reserves at locations greater distances from producing wells than immediate offsets. All proved reserves are required to meet reasonable certainty standards; thus, locations more than direct offsets to producing wells must be shown to be underlain by the productive formation. Reasonable certainty also requires that the formation is continuous between the producing wells and the PUD locations and that the PUDs are economically viable.

 

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Our proved reserves as of December 31, 2011 included PUDs more than directly offsetting producing wells in three resource plays: the Barnett Shale, the Haynesville Shale and the Marcellus Shale. In all other areas, we restricted PUD locations to immediate offsets to producing wells. Within the Barnett, Haynesville and Marcellus Shale plays, we used both public and proprietary geologic data to establish continuity of the formation and its producing properties. This included seismic data and interpretations (2-D, 3-D and micro seismic); open hole log information (collected both vertically and horizontally) and petrophysical analysis of the log data; mud logs; gas sample analysis; drill cutting samples; measurements of total organic content; thermal maturity; sidewall cores; whole cores; and data measured in our internal core analysis facility. After the geologic area was shown to be continuous, statistical analysis of existing producing wells was conducted to generate an area of reasonable certainty at distances from established production. Undrilled locations within this proved area could be booked as PUDs. However, due to other factors and requirements of the modernized rules, numerous locations within the proved area of these three statistically evaluated plays have not yet been booked as PUDs.

Our annual net decline rate on producing properties is projected to be 32% from 2012 to 2013, 20% from 2013 to 2014, 16% from 2014 to 2015, 13% from 2015 to 2016 and 11% from 2016 to 2017. Of our 10.106 tcfe of proved developed reserves as of December 31, 2011, 1.139 tcfe were non-producing.

Chesapeake’s ownership interest used in calculating proved reserves and the associated estimated future net revenue was determined after giving effect to the assumed maximum participation by other parties to our farmout and participation agreements. The prices used in calculating the estimated future net revenue attributable to proved reserves do not reflect market prices for natural gas and oil production sold subsequent to December 31, 2011. The estimated proved reserves may not be produced and sold at the assumed prices.

The Company’s estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2011, 2010 and 2009, and the changes in quantities and standardized measure of such reserves for each of the three years then ended, are shown in Note 10 of the notes to the consolidated financial statements included in Item 8 of this report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material. Accordingly, reserve estimates are often different from the actual quantities of natural gas and oil that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate.

Chesapeake’s management uses forward-looking market-based data in developing its drilling plans, assessing its capital expenditure needs and projecting future cash flows. We believe that using the 10-year average future NYMEX strip prices yields a better indication of the likely economic producibility of proved reserves than the trailing average 12-month price required by the SEC’s reserves rules or a period-end spot price, as used under the SEC rules before December 31, 2009.

 

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Reserve volumes represent estimated production to be sold in the future. Futures prices, such as the 10-year average NYMEX strip prices, represent an unbiased consensus estimate by market participants about the likely prices to be received for future production. We hedge substantial amounts of future production based on futures prices. While historical data, such as the trailing 12-month average price required by the SEC’s reporting rule, facilitate comparisons of proved reserves from company to company and may be helpful in discerning trends, such as price-related effects on end-user demand, the price at which we can sell our production in the future is by far the major determinant of the likely economic producibility of our reserves. A 12-month average price adjusts slowly to falling or rising prices, further detracting from its usefulness as a predictor of the prices at which future production will actually be sold.

The table below compares our estimated proved reserves and associated present value (discounted at an annual rate of 10%) of estimated future revenue before income tax using the 2011 12-month average prices of $4.12 per mcf and $95.97 per bbl, before price differential adjustments, reflected in our reported reserve estimates and the 10-year average future NYMEX strip prices as of December 31, 2011, which were $4.92 per mcf and $92.61 per barrel, before price differential adjustments. Our cost and other assumptions are the same under the two pricing scenarios.

 

     December 31, 2011  
     Gas
(bcf)
     Oil
(mmbbl)(a)
     Total
(bcfe)
     Present Value
($ in millions)
 

2011 12-month average prices (SEC)(b)

     15,515         545.5         18,789       $ 19,878   

10-year average future NYMEX strip prices as of December 31, 2011(c)

     16,579         551.3         19,887       $ 23,844   

 

(a)

Includes NGLs.

 

(b)

Volumes represent proved reserves as defined in Rule 4-10(a)(22) of Regulation S-X.

 

(c)

Volumes do not represent proved reserves as defined in Rule 4-10(a)(22) of Regulation S-X.

Reserves Estimation

Chesapeake’s Reservoir Engineering Department prepared approximately 23% (compared to 22% in 2010) of the proved reserves estimates (by volume) disclosed in this report based upon a review of production histories and other geologic, economic, ownership and engineering data we developed. The estimates were not based on any single significant assumption due to the diverse nature of the reserves and there is no significant concentration of proved reserve volume or value in any one well or field. The department currently has a total of 116 full-time employees, consisting of 69 degreed engineers (ten serving in management capacities), 45 engineering technicians with a minimum of a four-year degree in mathematics, economics, finance or other business/science field, and two administrative persons. Twelve of our engineers are registered professional engineers with various state board certifications. The department collectively has approximately 1,700 years of industry experience. Chesapeake maintains a continuous education program for engineers and technicians on new technologies and industry advancements and also offers refresher training on basic skill sets.

We maintain internal controls such as the following to ensure the reliability of reserves estimations:

 

   

We follow comprehensive SEC-compliant internal policies to determine and report proved reserves. Reserves estimates are made by experienced reservoir engineers or under their direct supervision.

 

   

The Reservoir Engineering Department reviews all of the Company’s reported proved reserves at the close of each quarter.

 

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Each quarter, Reservoir Engineering Department managers, the Vice President of Corporate Reserves, the Senior Vice President of Production and the Chief Operating Officer review all significant reserves changes and all new proved undeveloped reserves additions.

 

   

The Reservoir Engineering Department reports independently of any of our operating divisions.

Chesapeake’s Vice President of Corporate Reserves is the technical person primarily responsible for overseeing the preparation of the Company’s reserve estimates. His qualifications include the following:

 

   

36 years of practical experience in petroleum engineering with 33 years of this experience being in the estimation and evaluation of reserves

 

   

certified professional engineer in the state of Oklahoma

 

   

Bachelor of Science degree in Petroleum Engineering

 

   

member in good standing of the Society of Petroleum Engineers

We engaged four third-party engineering firms to prepare portions of our reserves estimates comprising approximately 77% of our estimated proved reserves (by volume) at year-end 2011. The portion of our estimated proved reserves prepared by each of our third-party engineering firms as of December 31, 2011 is presented below.

 

     % Prepared
(by Volume)
  

Principal Properties

Netherland, Sewell & Associates, Inc.

   42%   

Northern, Southern, Western

Ryder Scott Company, L.P.

   19%   

Northern

Lee Keeling and Associates, Inc.

   9%   

Northern, Southern, Western

Data & Consulting Services, Division of Schlumberger Technology Corporation

   7%   

Eastern

Copies of the reports issued by the engineering firms are filed with this report as Exhibits 99.1 - 99.4. The qualifications of the technical person at each of these firms primarily responsible for overseeing his firm’s preparation of the Company’s reserve estimates are set forth below.

Netherland, Sewell & Associates, Inc.:

 

   

over 29 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves

 

   

a registered professional engineer in the state of Texas

 

   

Bachelor of Science degree in Petroleum Engineering

Ryder Scott Company, L.P.:

 

   

over 30 years of practical experience in the estimation and evaluation of reserves

 

   

registered professional engineer in the state of Texas

 

   

Bachelor of Science degree in Electrical Engineering

 

   

member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers

 

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Lee Keeling and Associates, Inc.:

 

   

over 45 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves

 

   

a certified professional engineer in the state of Oklahoma

 

   

Bachelor of Science degree in Petroleum Engineering

Data & Consulting Services, Division of Schlumberger Technology Corporation:

 

   

over 20 years of practical experience in petroleum geology and in the estimation and evaluation of reserves

 

   

registered professional geologist license in the commonwealth of Pennsylvania

 

   

certified petroleum geologist of the American Association of Petroleum Geologists

 

   

Bachelor of Science degree in Geological Sciences

Drilling and Completion, Acquisition and Divestiture Activities

The following table sets forth historical cost information regarding our drilling and completion, acquisition and divestiture activities during the periods indicated:

 

     December 31,  
     2011     2010     2009  
     ($ in millions)  

Drilling and completion costs:

      

Development(a)

   $ 5,495      $ 4,739      $ 2,729   

Exploratory(b)(c)

     2,260        872        813   

Asset retirement obligation and other

     3        2        (2
  

 

 

   

 

 

   

 

 

 
     7,758        5,613        3,540   

Acquisition costs:

      

Unproved properties(d)

     4,736        6,953        2,793   

Proved properties

     48        243        61   
  

 

 

   

 

 

   

 

 

 
     4,784        7,196        2,854   

Proceeds from divestitures:

      

Unproved properties

     (4,943     (1,524     (1,265

Proved properties

     (2,612     (2,876     (461
  

 

 

   

 

 

   

 

 

 
     (7,555     (4,400     (1,726
  

 

 

   

 

 

   

 

 

 

Total

   $ 4,987      $ 8,409      $ 4,668   
  

 

 

   

 

 

   

 

 

 

 

(a)

Includes capitalized internal costs of $399 million, $353 million and $337 million, respectively.

 

(b)

Includes capitalized internal costs of $18 million, $16 million and $22 million, respectively.

 

(c)

Includes related capitalized interest of $18 million, $24 million and $29 million, respectively.

 

(d)

Includes related capitalized interest of $709 million, $687 million and $598 million, respectively.

Our development costs included $1.477 billion, $789 million and $621 million in 2011, 2010 and 2009, respectively, related to properties carried as proved undeveloped locations in the prior year’s reserve reports.

 

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A summary of our drilling and completion, acquisition and divestiture activities in 2011 by operating division is as follows:

 

    Gross
Wells
Drilled
    Net
Wells
Drilled
    Drilling
and
Completion(a)
    Acquisition
of
Unproved
Properties(b)
    Acquisition
of
Proved
Properties
    Sales
of
Unproved
Properties
    Sales
of
Proved
Properties
    Total  
    ($ in millions)  

Southern

    1,104        550          $ 2,722          $ 740          $ 12          $ (515       $ (56       $ 2,903   

Northern

    1,076        342        1,791        1,280        16        (2,577     (2,488     (1,978

Eastern

    371        149        1,515        1,523        20        (979     (50     2,029   

Western

    428        241        1,730        1,193               (872     (18     2,033   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    2,979        1,282          $ 7,758          $ 4,736          $ 48          $ (4,943       $ (2,612       $ 4,987   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(a)

Includes capitalized internal costs of $417 million and related capitalized interest of $18 million.

 

(b)

Includes related capitalized interest of $709 million.

Acreage

The following table sets forth as of December 31, 2011 the gross and net developed and undeveloped natural gas and oil leasehold and fee mineral acreage. “Gross” acres are the total number of acres in which we own a working interest. “Net” acres refer to gross acres multiplied by our fractional working interest. Acreage numbers do not include our options to acquire additional acreage which have not been exercised.

 

     Developed
Leasehold
     Undeveloped
Leasehold
     Fee
Minerals
     Total  
     Gross
Acres
     Net
Acres
     Gross
Acres
     Net
Acres
     Gross
Acres
     Net
Acres
     Gross
Acres
     Net
Acres
 
     (in thousands)  

Southern

     1,009         654         481         270         136         64         1,626         988   

Northern

     4,583         2,333         4,176         2,726         667         184         9,426         5,243   

Eastern

     1,982         1,534         6,380         3,690         683         523         9,045         5,747   

Western

     903         499         5,419         2,759         239         23         6,561         3,281   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     8,477         5,020         16,456         9,445         1,725         794         26,658         15,259   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

We actively acquire new leases, most of which have a three to five year term. Managing lease expirations to ensure that we do not experience unintended material expirations is an important part of our business. Our leasehold management efforts include scheduling our drilling to establish production in paying quantities in order to hold leases by production, timely exercising our contractual rights to pay delay rentals to extend the terms of leases we value, planning leasehold asset sales and industry participation transactions to high-grade our lease inventory or to raise capital for additional development and letting some low-value leases expire.

 

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The following table sets forth as of December 31, 2011, the expiration periods of gross and net undeveloped leasehold acres, unless production from the leasehold acreage is established prior to the expiration date, or we take action to extend the lease term.

 

         Acres Expiring(a)      
     Gross
Acres
     Net
Acres
 
     (in thousands)  

Years Ending December 31:

     

2012

     2,075         1,081   

2013

     3,486         1,980   

2014

     3,327         2,212   

After 2014 and other(b)

     7,568         4,172   
  

 

 

    

 

 

 

Total

     16,456         9,445   
  

 

 

    

 

 

 

 

(a)

We maintain a very large drilling program that is rigorously scheduled to lock in our acreage with the highest prospective value. Our control of a substantial rig fleet and other oilfield services assets gives us a high degree of confidence that we will be able to execute our drilling plans. We have determined that the amount of undeveloped leasehold that we reasonably believe will be abandoned or allowed to expire at the end of the lease term is immaterial to our operations.

(b)

Includes held-by-production acreage that will remain in force as production continues on the subject leases, and other leasehold acreage where management anticipates the lease to remain in effect past the primary term of the agreement due to our contractual right to extend the lease term.

Marketing, Gathering and Compression

Marketing

Chesapeake Energy Marketing, Inc. (CEMI), one of our wholly owned subsidiaries, provides natural gas and oil marketing services, including commodity price structuring, contract administration and nomination services for Chesapeake, its joint working interest owners and other producers. We attempt to enhance the value of our natural gas and oil production by aggregating volumes to be sold to various intermediary markets, end markets and pipelines. This aggregation allows us to attract larger, more creditworthy customers that in turn assist in maximizing the prices received for our production.

Our oil production is generally sold under market sensitive or spot price contracts. The revenue we receive from the sale of natural gas liquids is included in oil sales.

Our natural gas production is sold to purchasers under percentage-of-proceeds contracts, percentage-of-index contracts or spot price contracts. By the terms of the percentage-of-proceeds contracts, we receive a percentage of the resale price received by the purchaser after transportation and processing of our natural gas. Under percentage-of-index contracts, the price per mmbtu we receive for our natural gas is tied to indexes published in Inside FERC or Gas Daily. Although exact percentages vary daily, as of February 2012, approximately 80% of our natural gas production was sold under short-term contracts at market-sensitive prices. No customer accounted for more than 10% of total revenues (excluding gains (losses) on derivatives) in 2011.

Our marketing activities, along with our midstream gathering and compression operations described below, constitute a reportable segment under accounting guidance for disclosure about segments of an enterprise and related information. See Note 17 of the notes to our consolidated financial statements in Item 8 of this report.

 

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Midstream Gathering Operations

Chesapeake invests in gathering systems and processing facilities to complement our natural gas operations in regions where we have significant production and additional infrastructure is required. By doing so, we are better able to manage the value received for and the costs of, gathering, treating and processing natural gas. These systems are designed primarily to gather Company production for delivery into major intrastate or interstate pipelines. In addition, our midstream business provides services to joint working interest owners and other third-party customers. Chesapeake generates revenues from its gathering, treating and compression activities through fixed-rate fee structures. The Company also processes a portion of its natural gas at various third-party plants.

Our midstream assets are held and operated by our wholly owned subsidiary, Chesapeake Midstream Development, L.P. (CMD), and its subsidiaries. The CMD systems are located in Oklahoma, Texas, New Mexico, New York, Ohio, Louisiana, Pennsylvania, Wyoming and West Virginia and consist of approximately 1,950 miles of gathering pipelines, servicing over 1,900 natural gas wells. The majority of the CMD systems are in developing areas and will require significant build-out capital expenditures. A source of liquidity for CMD’s business is the $600 million revolving bank credit facility described under Liquidity and Capital Resources in Item 7 below.

We also invest in midstream operations through our affiliate, Chesapeake Midstream Partners, L.P. (CHKM), a master limited partnership which we and Global Infrastructure Partners-A, L.P. and affiliated funds managed by Global Infrastructure Management, LLC and certain of their respective subsidiaries and affiliates (collectively, GIP) formed in 2010 to own, operate, develop and acquire gathering systems and other midstream energy assets. As of December 31, 2011, public security holders, GIP and Chesapeake owned 23.5%, 30.4% and 46.1%, respectively, of all outstanding CHKM limited partner interests. CHKM limited partners, collectively, have a 98.0% interest in CHKM, and the general partner, which is owned and controlled 50/50 by Chesapeake and GIP, has a 2.0% interest in CHKM. CHKM common units representing limited partner interests trade on the New York Stock Exchange. CHKM 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. CHKM currently operates in Texas, Louisiana, Oklahoma, Kansas, Arkansas, Pennsylvania and West Virginia and provides gathering, treating and compression services to Chesapeake and other leading producers under long-term, fixed-fee contracts.

CHKM completed its initial public offering of common units on August 3, 2010 and received net offering proceeds of approximately $475 million at an initial offering price of $21.00 per unit. In connection with the closing of the offering and pursuant to the terms of our contribution agreement with GIP, CHKM distributed to GIP the approximate $62 million of net proceeds from the exercise of the over-allotment option granted to the underwriters of the offering. Prior to the initial public offering, in September 2009, we and GIP formed a joint venture to own and operate natural gas midstream assets. As part of the transaction, CMD contributed certain natural gas gathering systems to the newly formed joint venture entity, and GIP purchased a 50% interest for $588 million in cash. The assets we contributed to the joint venture were substantially all of our midstream assets in the Barnett Shale and also the majority of our non-shale midstream assets in the Arkoma, Anadarko, Delaware and Permian Basins. Chesapeake and GIP contributed the interests of the midstream joint venture’s operating subsidiary to CHKM in connection with the closing of CHKM’s initial public offering.

CHKM has significant potential long-term growth opportunities, including through its rights of first offer on certain future CMD midstream divestitures as well as through the development and acquisition of additional midstream assets adjacent to our existing areas of operation. In December 2010, CMD sold its Springridge natural gas gathering system and related facilities in the Haynesville Shale to CHKM for $500 million. In connection with this transaction, CHKM and certain Chesapeake subsidiaries entered into ten-year gas gathering and compression agreements covering Chesapeake’s and other producers’ upstream assets within an area of dedication around the existing pipeline system.

 

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The gathering and compression agreements are similar to the previously existing gathering agreement put in place upon the closing of the CHKM initial public offering and include a minimum volume commitment and periodic rate redetermination.

In December 2011, CMD sold its wholly owned subsidiary, Appalachia Midstream Services, L.L.C. (AMS), which held certain of our Marcellus Shale midstream assets, to CHKM for total consideration of $879 million. We and other producers in the area have entered into 15-year fixed fee gathering agreements that include significant acreage dedications and annual fee redeterminations. In addition, CMD has committed to pay CHKM quarterly any shortfall between the actual EBITDA from these assets and specified quarterly targets, which targets total $100 million in 2012 and $150 million in 2013. See Note 11 of the notes to our consolidated financial statements in Item 8 for further discussion.

As of December 31, 2011, CHKM’s systems consisted of approximately 3,630 miles of gathering pipelines, servicing approximately 4,965 natural gas wells and gathering approximately 2.2 bcf of natural gas per day.

Compression

Since 2003, Chesapeake has expanded its compression business. Our wholly owned subsidiary, MidCon Compression, L.L.C. (MidCon), operates wellhead and system compressors, with over 1.0 million horsepower of compression, to facilitate the transportation of natural gas primarily produced from Chesapeake-operated wells. In a series of transactions since 2007, MidCon sold 2,542 compressors (net of six repurchased units), a significant portion of its compressor fleet, for $635 million and entered into a master lease agreement. These transactions were recorded as sales and operating leasebacks.

Oilfield Services

We formed Chesapeake Oilfield Services, L.L.C. (COS) in 2011 to own and operate our oilfield services assets. COS is a diversified oilfield services company that provides a wide range of well site services, primarily to Chesapeake and its working interest partners. COS focuses on providing services that we have identified as scarce or as having relatively high margins. These services include contract drilling, pressure pumping, tool rental, transportation and manufacturing of natural gas compressor packages and related production equipment. These services are fundamental to establishing and maintaining the flow of natural gas and oil throughout the productive life of a well. A source of liquidity for COS’s business is the $500 million revolving bank credit facility described under Liquidity and Capital Resources in Item 7 of this report. Additionally, in October 2011, Chesapeake Oilfield Operating, L.L.C. (COO), a wholly owned subsidiary of COS, issued $650 million principal amount of 6.625% Senior Notes due 2019 in a private placement. Proceeds from this placement were used to make a cash distribution to its direct parent, COS, to enable it to reduce indebtedness under an intercompany note with Chesapeake.

Our oilfield services operations constitute a reportable segment under accounting guidance for disclosure about segments of an enterprise and related information. See Note 17 of the notes to our consolidated financial statements in Item 8 of this report. COS conducts operations through five lines of business, as described below.

Contract Drilling

Securing available rigs is an integral part of the exploration process and therefore owning our own drilling company is a strategic advantage for us. In 2001, we formed our wholly owned drilling subsidiary, Nomac Drilling, L.L.C., with an investment of $26 million to build and refurbish five drilling rigs. As of December 31, 2011, we had invested approximately $1.5 billion to build or acquire 132 drilling rigs, which are utilized primarily to drill Chesapeake-operated wells. In a series of transactions since 2006, our drilling subsidiaries sold 93 drilling rigs (net of one repurchased rig) and related equipment for $802 million and subsequently leased back the rigs through 2018. These transactions

 

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were recorded as sales and operating leasebacks. The drilling rigs have depth ratings between 3,000 and 25,000 feet and range in drilling horsepower from 450 to 2,000. These drilling rigs are currently operating in Oklahoma, Texas, Louisiana, West Virginia, Pennsylvania, Ohio and North Dakota. As of December 31, 2011, we had a fleet of 39 owned and 93 leased land drilling rigs, 114 of which we were operating, making us the fourth largest land driller operating in the U.S.

Pressure Pumping

In 2010, we began the process of building a pressure pumping business under the name of Performance Technologies, L.L.C. (PTL). As part of that effort, we purchased two hydraulic fracturing fleets with an aggregate of 60,000 horsepower, one of which was deployed in the 2011 fourth quarter and the other in the 2012 first quarter. We use our pressure pumping assets to provide hydraulic fracturing and other well stimulation services. We plan to have nine fleets with an aggregate of approximately 340,000 horsepower operating by the first quarter of 2013 and plan to build PTL into one of the nation’s five largest pressure pumping companies.

Oilfield Rentals

Our oilfield rentals segment provides premium rental tools for land oil and natural gas drilling and workover activities under the name Great Plains Oilfield Rental, L.L.C. We offer our customers a number of products and services, including drill pipe, drill collars, tubing, high and low pressure blowout preventers, water transfer, frac tanks, mud tanks and mud systems. As of December 31, 2011, we owned 2,074 frac tanks and 1.5 million feet of drill pipe.

Oilfield Trucking

In 2006, we expanded our oilfield services by acquiring two privately owned oilfield trucking service companies. We now own one of the largest oilfield and heavy haul transportation companies in the industry under the names of Hodges Trucking, L.L.C. and Oilfield Trucking Solutions, L.L.C. Our trucking business provides rig relocation and logistics services as well as fluid hauling services. Our trucks move drilling rigs, water, crude oil, other fluids and construction materials. As of December 31, 2011, we owned a fleet of 202 rig relocation trucks, 56 cranes and forklifts used in the movement of drilling rigs and other heavy equipment and 127 fluid service trucks.

Compressor Manufacturing

Our compressor manufacturing business operates under the name of Compass Manufacturing, L.L.C. and consists of natural gas compressor manufacturing operations in which we design, engineer, fabricate, install and sell natural gas compression units, accessories and equipment used in the production, treatment and processing of natural gas and oil. Once the compressors are complete, they are sold to MidCon and put into service for Chesapeake-operated wells.

Competition

We compete with both major integrated and other independent natural gas and oil companies in acquiring desirable leasehold acreage, producing properties and the equipment and expertise necessary to explore, develop and operate our properties and market our production. Some of our competitors may have larger financial and other resources than ours. Competitive conditions may be affected by future legislation and regulations as the U.S. develops new energy and climate-related policies. In addition, some of our larger competitors may have a competitive advantage when responding to factors that affect demand for natural gas and oil production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities, and overall economic conditions. We believe that our technological expertise, our exploration, land, drilling and production capabilities and the experience of our management generally enable us to compete effectively.

 

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Hedging Activities

We utilize hedging strategies to hedge the price of a portion of our future natural gas and oil production and to manage interest rate exposure. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Regulation

General

All of our operations are conducted onshore in the U.S. The U.S. natural gas and oil industry is regulated at the federal, state and local levels, and some of the laws, rules and regulations that govern our operations carry substantial administrative, civil and criminal penalties for non-compliance. Although we believe we are in substantial compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations could be, and frequently are, amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance or non-compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the courts and federal agencies, such as the U.S. Environmental Protection Agency (EPA), the Federal Energy Regulatory Commission, the Department of Transportation, the Department of Interior and the Department of Energy. We actively monitor regulatory developments regarding our industry in order to anticipate and design required compliance activities and systems.

Exploration and Production Operations

The laws and regulations applicable to our exploration and production operations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to such laws and regulations include, but are not limited to:

 

   

the location of wells;

 

   

the method of drilling and completing wells;

 

   

the surface use and restoration of properties upon which wells are drilled;

 

   

water withdrawal;

 

   

the plugging and abandoning of wells;

 

   

the disposal of fluids used or other wastes generated in connection with operations;

 

   

the marketing, transportation and reporting of production; and

 

   

the valuation and payment of royalties.

Our operations may require us to obtain permits for, among other things,

 

   

air emissions;

 

   

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

 

   

the construction and operation of underground injection wells to dispose of produced saltwater and other non-hazardous oilfield wastes; and

 

   

the construction and operation of surface pits to contain drilling muds and other non-hazardous fluids associated with drilling operations.

 

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Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with provisions of our permits could result in revocation of such permits and the imposition of fines and penalties.

Our exploration and production activities are also subject to various conservation regulations. These include the regulation of the size of drilling and spacing units (regarding the density of wells that may be drilled in a particular area) and the unitization or pooling of natural gas and oil properties. In this regard, some states, such as Oklahoma, allow the forced pooling or integration of tracts to facilitate exploration, while other states, such as Texas and Pennsylvania, rely on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units and therefore, more difficult to fully develop a project if the operator owns or controls less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amount of natural gas and oil we can produce and to limit the number of wells and the locations at which we can drill.

Midstream Operations

In addition to the environmental, health and safety laws and regulations discussed below under Environmental, Health and Safety Matters, our midstream facilities are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (PHMSA) of the U.S. 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 inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

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 with regard to any of our facilities, we believe that our natural gas pipelines and related facilities are engaged in exempt gathering and intrastate transportation and, therefore, are not subject to FERC jurisdiction.

FERC regulation affects our gathering and compression business generally. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on

 

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open access transportation, market manipulation, ratemaking, capacity release and market transparency and market center promotion, indirectly affect our gathering business. In addition, the distinction between FERC-regulated transmission facilities and federally unregulated gathering and intrastate transportation facilities is a fact-based determination made by FERC on a case by case basis; this distinction has also been the subject of regular litigation and change. The classification and regulation of our gathering and intrastate transportation facilities are subject to change based on future determinations by FERC, the courts or Congress.

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

Oilfield Services Operations

Our oilfield services business operates under the jurisdiction of a number of regulatory bodies that regulate worker safety standards, the handling of hazardous materials, the transportation of explosives, the protection of the environment and driving standards of operation. Regulations concerning equipment certification create an ongoing need for regular maintenance that is incorporated into our daily operating procedures.

In providing trucking services, we operate as a motor carrier and therefore are subject to regulation by the DOT and various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety, financial reporting and certain mergers, consolidations and acquisitions. Interstate motor carrier operations are subject to safety requirements prescribed by the DOT and, to a large degree, intrastate motor carrier operations are subject to safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations, and DOT regulations mandate drug testing of drivers. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements.

The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations that govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.

Environmental, Health and Safety Matters

Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of human health and safety, the environment and natural resources. 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;

 

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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 or restoration 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 substantial compliance with changing environmental laws and regulations and to reduce the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations and that share best practices and lessons learned.

Below is a discussion of the material environmental, health and safety laws and regulations that relate to our business. We believe that we are in substantial compliance with these laws and regulations. We do not believe that compliance with existing environmental, health and safety laws or regulations will have a material adverse effect on our financial condition, results of operations or cash flow. At this point, however, we cannot reasonably predict what applicable laws, regulations or guidance may eventually be adopted with respect to our operations or the ultimate cost to comply with such requirements.

Hazardous Substances and Waste

Federal and state laws, in particular the Federal Resource Conservation and Recovery Act, or RCRA, regulate hazardous and non-hazardous solid wastes. In the course of our operations, we generate petroleum hydrocarbon wastes such as produced water and ordinary industrial wastes. Under a longstanding legal framework, certain of these wastes are not subject to federal regulations governing hazardous wastes, although they are regulated under other federal and state laws.

Federal, state and local laws may also require us to remove or remediate previously disposed wastes or hazardous substances otherwise released into the environment, including wastes or hazardous substances disposed of or released by us or prior owners or operators in accordance with current laws or otherwise, to suspend or cease operations at contaminated areas, or to perform remedial well plugging operations or response actions to reduce the risk of future contamination. Federal laws, including the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and analogous state laws impose joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered responsible for releases of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and persons that disposed of or arranged for the disposal of hazardous substances at the site. CERCLA and analogous state laws also authorize the EPA, state environmental agencies and, in some cases, third parties to take action to prevent or respond to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such actions.

 

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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 impose various monitoring and reporting requirements. The EPA has published proposed New Source Performance Standards (NSPS) and National Emissions Standards for Hazardous Air Pollutants (NESHAP) that, if adopted as proposed, would amend existing NSPS and NESHAP standards for oil and gas facilities as well as create new NSPS standards for oil and gas production, transmission and distribution facilities.

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 placement of material into jurisdictional water or wetlands of the U.S. is prohibited, except in accordance with the terms of a permit issued by the United States Army Corps of Engineers. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a state agency delegated with EPA’s authority. Further, Chesapeake’s corporate policy prohibits discharge of produced water to surface waters. 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.

The Oil Pollution Act of 1990, or OPA, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the U.S.

Hydraulic Fracturing

Vast quantities of natural gas, natural gas liquids and oil deposits exist in deep shale and other unconventional formations. It is customary in our industry to recover these resources from these deep formations through the use of hydraulic fracturing, combined with horizontal drilling. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in deep underground formations using water, sand and other additives pumped under high pressure into the formation. As with the rest of the industry, we use hydraulic fracturing as a means to increase the productivity of almost every well that we drill and complete. These formations are generally geologically separated and isolated from fresh ground water supplies by thousands of feet of impermeable rock layers.

We follow applicable legal requirements for groundwater protection in our operations that are subject to supervision by state and federal regulators (including the Bureau of Land Management on federal acreage). Furthermore, our well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into aquifers.

Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Hydraulic fracturing operations are shut down immediately if an abrupt change occurs to the injection pressure or annular pressure. These aspects of well construction are designed to eliminate a pathway for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations.

 

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Hydraulic fracture stimulation requires the use of water. We use fresh water in our fracturing treatments in accordance with applicable water management plans and laws. We strive to find alternative sources of water and minimize our reliance on fresh water resources. We have technical staff dedicated to the development of water recycling and re-use systems, and our Aqua Renew® program uses state-of-the-art technology in an effort to recycle produced water in our operations.

Produced, or formation, water is a naturally occurring by-product of natural gas and liquids extraction. Chesapeake disposes of produced formation water in Class II underground injection control wells, which are designed and permitted to place the water into deep geologic formations, isolated from fresh water sources. These Class II wells are overseen by the EPA in its Underground Injection Control Program.

Some states have adopted, and other states are considering adopting, regulations that impose disclosure requirements on hydraulic fracturing operations. Since early 2011, we have voluntarily participated in FracFocus, a national publicly accessible web-based registry developed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission, with support of the U.S. Department of Energy, to report on a well-by-well basis the additives and chemicals and amount of water used in the hydraulic fracturing process for each of the wells we operate. The website, www.fracfocus.org, also includes information about how hydraulic fracturing works, the chemicals used in hydraulic fracturing and how fresh water aquifers are protected. Some states, such as Texas, Colorado, Montana, Louisiana and North Dakota, which mandate disclosure of chemical additives used in hydraulic fracturing require operators to use the FracFocus website for reporting.

Legislative, regulatory and enforcement efforts, as well as guidance from regulatory agencies, at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Hydraulic fracturing is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the process of drafting guidance documents for permitting authorities and the industry on the process for obtaining a permit for hydraulic fracturing involving diesel fuel. While we believe such permitting would not materially affect our operations because we do not use diesel fuel in connection with our hydraulic fracturing, industry groups have filed suit challenging the EPA’s assertion of authority as improper rule making. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with initial study results anticipated to be available by late 2012. The results of EPA’s guidance, including its definition of diesel fuel, the related litigation, EPA’s study, and other analyses by federal and state agencies to assess the impacts of hydraulic fracturing could each spur further action toward federal legislation and regulation of hydraulic fracturing activities. Also, for the second consecutive session, legislation has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process.

Restrictions on hydraulic fracturing could make it prohibitive to conduct our operations, and also reduce the amount of oil, natural gas liquids and natural gas that we are ultimately able to produce in commercial quantities from our properties. For further discussion, see Item 1A. Risk Factors – Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

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

 

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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

Various state governments and regional organizations are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations. At the federal level, the EPA has already made findings and issued regulations that require us to establish and report an inventory of greenhouse gas emissions. Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the natural gas and oil that we sell. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program.

Title to Properties

Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the natural gas and oil industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the natural gas and oil industry. Nevertheless, we are involved in title disputes from time to time which result in litigation.

Operating Hazards and Insurance

The natural gas and oil business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, Chesapeake could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.

Chesapeake maintains a $75 million control of well policy that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. There is no assurance that this insurance will be adequate to cover all losses or exposure to liability. Chesapeake also carries a $425 million comprehensive general liability umbrella policy and a $150 million pollution liability policy. We provide workers’ compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. The insurance coverage that we maintain may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.

 

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Facilities

Chesapeake owns an office complex in Oklahoma City and we continue to construct additional buildings in Oklahoma City and in our operating areas as needed to accommodate our ongoing growth. We also own or lease various field or administrative offices in approximately 110 cities or towns in the areas where we conduct our operations.

Employees

Chesapeake had approximately 12,600 employees as of December 31, 2011.

Glossary of Natural Gas and Oil Terms

The terms defined in this section are used throughout this Form 10-K.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bcf. Billion cubic feet.

Bcfe. Billion cubic feet of natural gas equivalent.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Commercial Well; Commercially Productive Well. A natural gas and oil well which produces natural gas and oil in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

Conventional Reserves. Natural gas and oil occurring as discrete accumulations in structural and stratigraphic traps.

Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Drilling Carry Obligation. An obligation of one party to pay certain well costs attributable to another party.

Dry Hole; Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as a natural gas or oil well.

Exploratory Well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir.

Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.

Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.

 

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Full Cost Pool. The full cost pool consists of all costs associated with property acquisition, exploration and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.

Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal Wells. Wells which are drilled at angles greater than 70 degrees from vertical.

Karst. An area of irregular limestone in which erosion has produced fissures, sinkholes, underground streams and caverns.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet of natural gas equivalent.

Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.

Mmbtu. One million btus.

Mmcf. One million cubic feet.

Mmcfe. One million cubic feet of natural gas equivalent.

Natural Gas Liquids (NGLs). Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ethane, propane, butane, isobutene, pentane, hexane and natural gasoline.

Net Acres or Net Wells. The sum of the fractional working interests owned in gross acres or gross wells.

NYMEX. New York Mercantile Exchange.

Play. A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential natural gas and oil reserves.

Present Value or PV-10. When used with respect to natural gas and oil reserves, present value, or PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average natural gas and oil price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

Price Differential. The difference in the price of natural gas or oil received at the sales point and the New York Mercantile Exchange (NYMEX).

Productive Well. A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.

 

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Proved Developed Reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved Properties. Properties with proved reserves.

Proved Reserves. Proved natural gas and oil reserves are those quantities of natural gas and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of a reservoir considered as proved includes (i) the area indentified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of information on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved Undeveloped Reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

 

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Reserve Replacement. Calculated by dividing the sum of reserve additions from all sources (revisions, extensions, discoveries and other additions and acquisitions) by the actual production for the corresponding period. The values for these reserve additions are derived directly from the proved reserves table located in Note 10 of the notes to our consolidated financial statements included in Item 8 of this report. Management uses the reserve replacement ratio as an indicator of the Company’s ability to replenish annual production volumes and grow its reserves, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not imbed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty Interest. An interest in a natural gas and oil property entitling the owner to a share of oil or natural gas production free of costs of production.

Seismic. An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formation (3-D seismic provides three-dimensional pictures).

Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.

Standardized Measure of Discounted Future Net Cash Flows. The discounted future net cash flows relating to proved reserves based on the prices used in estimating the proved reserves, year-end costs and statutory tax rates (adjusted for permanent differences) and a 10% annual discount rate.

Tbtu. One trillion British thermal units.

Tcf. One trillion cubic feet.

Tcfe. One trillion cubic feet of natural gas equivalent.

Unconventional Reserves. Natural gas and oil occurring in regionally pervasive accumulations with low matrix permeability and close association with source rocks.

Undeveloped Acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

Unproved Properties. Properties with no proved reserves.

VPP. As we use the term, a volumetric production payment represents a limited-term overriding royalty interest in natural gas and oil reserves that (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser’s only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain the remaining reserves, if any, after the scheduled production volumes have been delivered.

Working Interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

 

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ITEM 1A. Risk Factors

Natural gas and oil prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.

Our revenues, operating results, profitability and ability to grow depend primarily upon the prices we receive for the natural gas and oil we sell. We require substantial expenditures to replace reserves, sustain production and fund our business plans. Lower natural gas or oil prices can negatively affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. In addition, lower prices may result in ceiling test write-downs of our natural gas and oil properties. We urge you to read the risk factors below for a more detailed description of each of these risks.

Historically, the markets for natural gas and oil have been volatile and they are likely to continue to be volatile. Wide fluctuations in natural gas and oil prices may result from relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and other factors that are beyond our control, including:

 

   

domestic and worldwide supplies of natural gas, natural gas liquids and oil, including U.S. inventories of natural gas and oil reserves;

 

   

weather conditions;

 

   

changes in the level of consumer demand;

 

   

the price and availability of alternative fuels;

 

   

the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;

 

   

the level and effect of trading in commodity futures markets, including by commodity price speculators and others;

 

   

the price and level of foreign imports;

 

   

the nature and extent of domestic and foreign governmental regulations and taxes;

 

   

the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

   

political instability or armed conflict in oil and gas producing regions; and

 

   

overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas and oil price movements with any certainty. Record-high supplies of natural gas and weak demand during one of the mildest winters on record in the U.S. have resulted in gas prices at 10-year lows in early 2012.

Further, the prices of natural gas and oil have not moved in tandem in recent years, creating a value gap that has caused us to shift our focus from dry gas plays to liquids-rich plays. While we anticipate that more than 50% of our 2012 revenue will come from our oil and natural gas liquids production, based on current NYMEX strip prices and our current hedging positions, approximately

 

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83% of our estimated reserves at December 31, 2011 were natural gas reserves. A substantial or extended decline in natural gas or oil prices could negatively affect the quantities of natural gas and oil reserves that may be economically produced.

We have historically hedged significant amounts of our anticipated production in order to mitigate a portion of our exposure to adverse market changes in natural gas and oil prices. While portions of our anticipated oil production are hedged through swaps and written call options, we currently have no natural gas price swaps that cover natural gas production. Our natural gas derivatives consist of written call options and basis protection swaps and cover only a small portion of our expected 2012 and 2013 natural gas production. As a consequence, our revenues and results of operations will be more significantly exposed to changes in commodity prices than in historical periods.

Our level of indebtedness may limit our financial flexibility.

As of December 31, 2011, we had long-term indebtedness of approximately $10.626 billion and unrestricted cash of $351 million, and our net indebtedness represented 38% of our total book capitalization, which we define as the sum of total Chesapeake stockholders’ equity and total current and long-term debt less unrestricted cash. We had $1.749 billion of outstanding borrowings drawn under our revolving bank credit facilities at December 31, 2011.

Our level of indebtedness affects our operations in several ways, including the following:

 

   

a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

 

   

we may be at a competitive disadvantage as compared to similar companies that have less debt;

 

   

the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

 

   

the midstream revolving bank credit facility, the oilfield services revolving bank credit facility and the indenture governing the COO 6.625% Senior Notes due 2019 restrict the payment of dividends or distributions to Chesapeake;

 

   

additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants; and

 

   

a lowering of the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings will increase the interest rate we pay on our corporate revolving bank credit facility.

The borrowing base of our corporate revolving bank credit facility is subject to periodic redetermination and is based in part on natural gas and oil prices. A lowering of our borrowing base because of lower natural gas and oil prices or for other reasons could require us to repay indebtedness in excess of the borrowing base, or we might need to further secure the lenders with additional collateral. We may incur additional debt, including secured indebtedness, in order to develop our properties and make future acquisitions. A higher level of indebtedness increases the risk that we may default on our obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gas and oil prices and financial, business and other factors affect our operations and our future performance.

 

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Many of these factors are beyond our control. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital. In addition, our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default under that indebtedness, which could adversely affect our business, financial condition and results of operations.

We recently announced an update to our operations and capital spending program in 2012, including our previously announced 25/25 Plan, pursuant to which we intend to engage in certain monetization transactions and apply a portion of the net proceeds to reduce our overall level of indebtedness. If we are unable to consummate such contemplated monetization transactions or if such transactions do not generate the proceeds we are anticipating, we would be required to reduce our capital spending, seek to identify, pursue and obtain funds from other monetization transactions or other sources in order to meet our operating, capital spending and debt reduction plans.

Declines in the prices of natural gas and oil could result in a write-down of our asset carrying values.

We utilize the full cost method of accounting for costs related to our natural gas and oil properties. Under this method, all such costs (for both productive and nonproductive properties) are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. However, these capitalized costs are subject to a ceiling test which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves discounted at 10% plus the lower of cost or market value of unproved properties. The full cost ceiling is evaluated at the end of each quarter using the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ending in the quarter, adjusted for the impact of derivatives accounted for as cash flow hedges. We are required to write down the carrying value of our natural gas and oil assets if capitalized costs exceed the ceiling limit, and such write-downs can be material. For example, our financial statements for the year ended December 31, 2009 reflect an impairment of approximately $6.9 billion, net of income tax, of our natural gas and oil properties.

The risk that we will be required to write down the carrying value of our natural gas and oil properties increases when natural gas and oil prices are low or volatile. Natural gas prices declined significantly in late 2011 and early 2012 to the lowest level in recent years and continue to trade near historic lows. Although we did not have an impairment of our natural gas and oil properties as of December 31, 2011, sustained low natural gas prices and other factors could cause us to be required to write down our natural gas and oil properties or other assets in the future and incur a non-cash charge against future earnings.

Significant capital expenditures are required to replace our reserves and conduct our business.

Our exploration, development and acquisition activities and our midstream and oilfield services businesses require substantial capital expenditures. We fund our capital expenditures through a combination of cash flows from operations and borrowings under our corporate, midstream and oilfield services revolving bank credit facilities and, to the extent those sources are not sufficient, from debt and equity issuances, subsidiary-level financings and asset monetizations. Future cash flows from operations are subject to a number of risks and variables, such as the level of production from existing wells, prices of natural gas and oil, our success in developing and producing new reserves and the other risk factors discussed herein. Our ability to obtain capital from other sources, such as the capital markets, subsidiary-level financing and asset monetizations, is dependent upon many of those same factors as well as the orderly functioning of credit and capital markets. We plan to make capital

 

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expenditures in 2012 that exceed our estimated 2012 cash flows from operations, and we anticipate funding this difference with the proceeds from transactions such as joint ventures, volumetric production payments, financial transactions, property and investment dispositions and other asset monetizations. To the extent that proceeds from these potential transactions are inadequate to fund our planned spending, we would be required to reduce our capital spending, seek to monetize different or additional assets or pursue other funding alternatives, and we would have a reduced ability to replace our reserves.

If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop or acquire additional natural gas and oil reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. In addition, approximately 46% of our total estimated proved reserves (by volume) at December 31, 2011 were undeveloped. Recovery of such reserves will require significant capital expenditures and successful drilling operations. Our reserve estimates at December 31, 2011 reflected a decline in the production rate on producing properties of approximately 32% in 2012 and 20% in 2013. Thus, our future natural gas and oil reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.

The actual quantities and present value of our proved reserves may be different than we have estimated.

This report contains estimates of our proved reserves and the estimated future net revenues from our proved reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating natural gas and oil reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to future revisions.

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing natural gas and oil prices and other factors, many of which are beyond our control.

At December 31, 2011, approximately 46% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our proved undeveloped reserves (PUDS) into proved developed reserves, including approximately $13.6 billion during the five years ending in 2016. You should be aware that the estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to write off any PUDs that are not developed within this five-year time frame.

You should not assume that the present values included in this report represent the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The

 

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price on the date of estimate is calculated as the average natural gas and oil price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2011 present value is based on $4.12 per mcf of natural gas and $95.97 per barrel of oil before price differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.

Any changes in consumption by natural gas and oil purchasers or in governmental regulations or taxation will also affect the actual future net cash flows from our production.

The timing of both the production and the expenses from the development and production of natural gas and oil properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with our business or the natural gas and oil industry in general will affect the accuracy of the 10% discount factor.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

We acquire significant amounts of unproved property in order to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

Drilling for natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and for other reasons. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for natural gas and crude oil, costs associated with producing natural gas and oil and our ability to add reserves at an acceptable cost. We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of unproved property or drilling a well, whether natural gas or oil is present or may be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. Drilling results in our newer natural gas and liquids-rich unconventional plays may be more uncertain than in unconventional plays that are more developed and have longer established production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other unconventional formations to maximize recoveries will be ultimately successful when used in new unconventional formations.

 

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Certain of our undeveloped leasehold assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage.

Leases on natural gas and oil properties typically have a term of three to five years after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. While we seek to actively manage our leasehold inventory using our drilling rig fleet and oilfield services to drill sufficient wells to hold the leasehold that we believe is material to our operations, our drilling plans for these areas are subject to change based upon various factors, including drilling results, natural gas and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

Our hedging activities may reduce the realized prices we receive for our natural gas and liquids sales, require us to provide collateral for hedging liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.

In order to manage our exposure to price volatility in marketing our production, we enter into natural gas and oil price risk management arrangements for a portion of our expected production. Commodity price derivatives may limit the prices we actually realize and therefore reduce natural gas and oil revenues in the future. Our commodity hedging activities will impact our earnings in various ways, including recognition of certain mark-to-market gains and losses on derivative instruments. The fair value of our natural gas and oil derivative instruments can fluctuate significantly between periods. In addition, our commodity price risk management transactions may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected.

Derivative transactions involve the risk that counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. Although the counterparties to our multi-counterparty secured hedging facility are required to secure their hedging obligations to us under certain scenarios, if any of our counterparties were to default on its obligations to us under the hedging contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes. The risk of counterparty default is heightened in a poor economic environment.

A substantial portion of our natural gas and oil derivative contracts are with the 18 counterparties to our multi-counterparty hedging facility. Our obligations under the facility are secured by natural gas and oil proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times. Under certain circumstances, such as a spike in volatility measures without a corresponding change in commodity prices, the collateral value could fall below the coverage designated, and we would be required to post additional reserve collateral to our hedging facility. If we did not have sufficient unencumbered natural gas and oil properties available to cover the shortfall, we would be required to post cash or letters of credit with the counterparties. Future collateral requirements are dependent to a great extent on natural gas and oil prices.

Natural gas and oil drilling and producing operations can be hazardous and may expose us to liabilities, including environmental liabilities.

Natural gas and oil operations are subject to many risks, including well blowouts, cratering and explosions, pipe failures, fires, formations with abnormal pressures, uncontrollable flows of natural gas, oil, brine or well fluids and other environmental hazards and risks. Some of these risks or hazards

 

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could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells, loss of equipment or otherwise negatively impacting the projected economic performance of our prospects. If any of these risks occurs, we could sustain substantial losses as a result of:

 

   

injury or loss of life;

 

   

severe damage to or destruction of property, natural resources or equipment;

 

   

pollution or other environmental damage;

 

   

clean-up responsibilities;

 

   

regulatory investigations and administrative, civil and criminal penalties; and

 

   

injunctions resulting in limitation or suspension of operations.

There is inherent risk of incurring significant environmental costs and liabilities in our operations due to our use, generation, handling and disposal of materials, including wastes, petroleum hydrocarbons and other chemicals. We may incur joint and several, strict liability under applicable U.S. federal and state environmental laws in connection with releases of petroleum hydrocarbons and other hazardous substances at, on, under or from our leased or owned properties resulting from current or historical operations. In some cases our properties have been used for natural gas and oil exploration and production activities for a number of years, often by third parties not under our control. We also could incur material fines, penalties and government or third-party claims as a result of violations of, or liabilities under, applicable environmental laws and regulations. For our non-operated properties, we are dependent on the operator for operational and regulatory compliance. While we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

It is customary in our industry to recover natural gas and oil from deep shale and other formations through the use of horizontal drilling combined with hydraulic fracturing. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in deep formations using water, sand and other additives pumped under high pressure into the formation. We use hydraulic fracturing as a means to increase the productivity of almost every well that we drill and complete.

The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Several states, including Pennsylvania, Texas, Colorado, Montana, New Mexico and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and/or well construction requirements on hydraulic fracturing operations. New York has sought to ban fracturing activities altogether. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.

Additionally, the EPA has asserted federal regulatory authority over hydraulic fracturing activities involving diesel fuel (specifically, when diesel fuel is utilized in the stimulation fluid) under the Safe Drinking Water Act and is completing the process of drafting guidance documents related to this newly asserted regulatory authority. There are also certain governmental reviews either underway or being

 

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proposed that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate such activities. The EPA has published proposed New Source Performance Standards (NSPS) and National Emissions Standards for Hazardous Air Pollutants (NESHAP) that, if adopted as proposed, would amend existing NSPS and NESHAP standards for oil and gas facilities as well as create new NSPS standards for oil and gas production, transmission and distribution facilities. The EPA has also proposed regulations focused on reducing emissions of certain air pollutants by the oil and gas industry, including volatile organic compounds, sulfur dioxide and certain air toxics.

Certain environmental and other groups have suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. We cannot predict whether additional federal, state or local laws or regulations will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed through the adoption of new laws and regulations, our business and operations could be subject to delays, increased operating and compliance costs and process prohibitions.

Potential legislative and regulatory actions could increase our costs, reduce our revenue and cash flow from natural gas and oil sales, reduce our liquidity or otherwise alter the way we conduct our business.

The activities of exploration and production companies operating in the U.S. are subject to extensive regulation at the federal, state and local levels. Changes to existing laws and regulations or new laws and regulations such as those described below could, if adopted, have an adverse effect on our business.

Federal Taxation of Independent Producers

Recent federal budget proposals would potentially increase and accelerate the payment of federal income taxes of independent producers of natural gas and oil. Proposals that would significantly affect us would repeal the expensing of intangible drilling costs, repeal the percentage depletion allowance and increase the amortization period of geological and geophysical expenses. These changes, if enacted, will make it more costly for us to explore for and develop our natural gas and oil resources.

OTC Derivatives Regulation

In July of 2010, the U.S. Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), which contains measures aimed at increasing the transparency and stability of the over-the-counter (OTC) derivative markets and preventing excessive speculation. We maintain an active price and basis protection hedging program related to the natural gas and oil we produce to manage the risk of low commodity prices and to predict with greater certainty the cash flow from our hedged production. We have used the OTC market exclusively for our natural gas and oil derivative contracts. The Dodd-Frank Act and the rules and regulations promulgated thereunder could reduce trading positions and the market-making activities of our customary counterparties in the energy futures markets. Such changes could materially reduce our hedging opportunities and negatively affect our revenues and cash flow during periods of low commodity prices.

Climate Change

Various state governments and regional organizations are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations. At the federal level, the EPA has already made findings and issued regulations that require us to establish and report an inventory of

 

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greenhouse gas emissions. Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the natural gas and oil that we sell. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Even without federal legislation or regulation of greenhouse gas emissions, states may pursue the issue either directly or indirectly. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and gas industry. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas and oil.

The decline in general economic, business and industry conditions since 2008 and the current economic uncertainty may have a material adverse effect on our results of operations, liquidity and financial condition.

Since 2008, concerns over sovereign debt levels, energy costs, geopolitical issues, the availability and cost of credit, the U.S. mortgage market and a declining real estate market in the U.S. have contributed to increased economic uncertainty and diminished expectations for the global economy.

These factors, combined with volatile natural gas and oil prices, the decline in business and consumer confidence and high unemployment, precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the U.S. or abroad deteriorates further, demand for petroleum products could continue to decline, prices for natural gas could continue to decrease and oil and natural gas liquids could become subject to increased downward price pressure. These circumstances could adversely impact our results of operations, liquidity and financial condition.

Our cash flow from operations, our revolving bank credit facilities and cash on hand historically have not been sufficient to fund all of our expenditures, and we have relied on the capital markets and asset monetization transactions to provide us with additional capital. Poor economic conditions may negatively affect:

 

   

our ability to access the capital markets at a time when we would like, or need, to raise capital;

 

   

the number of participants in our proposed asset monetization transactions or the values we are able to realize in those transactions, making them uneconomic or harder or impossible to consummate;

 

   

the collectability of our trade receivables could cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection; or

 

   

the ability of our joint venture partners to meet their obligations to fund a portion of our drilling costs under our joint venture agreements.

Our operations may be adversely affected by oilfield services shortages, pipeline and gathering system capacity constraints and various transportation interruptions.

From time to time, we experience delays in drilling and completing our natural gas and oil wells. Because of the large scale of our operations, there may not be available drilling rigs of the type we require in certain areas of our operations. Additionally, there is currently a shortage of hydraulic

 

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fracturing capacity, especially in the unconventional U.S. natural gas and oil plays where hydraulic fracturing is necessary for the successful development of wells. In developing plays, the demand for equipment such as pipe and compressors can exceed the supply, and it is challenging to attract and retain qualified oilfield workers. Delays in developing our natural gas and oil assets for these and other reasons could negatively affect our revenues and cash flow.

In certain natural gas shale plays, the capacity of gathering systems and transportation pipelines is insufficient to accommodate potential production from existing and new wells. Capital constraints could limit the construction of new pipelines and gathering systems by third parties, and we may experience delays in building intrastate gathering systems necessary to transport our natural gas to interstate pipelines. Until this new capacity is available, we may experience delays in producing and selling our natural gas. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.

A portion of our natural gas and oil production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions, an action we took in early 2012. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.

 

ITEM 1B. Unresolved Staff Comments

None.

 

ITEM 2. Properties

Information regarding our properties is included in Item 1 and in Note 10 of the notes to our consolidated financial statements included in Item 8 of this report.

 

ITEM 3. Legal Proceedings

Litigation

On February 25, 2009, a putative class action was filed in the U.S. District Court for the Southern District of New York against the Company and certain of its officers and directors along with certain underwriters of the Company’s July 2008 common stock offering. Following the appointment of a lead plaintiff and counsel, the plaintiff filed an amended complaint on September 11, 2009 alleging that the registration statement for the offering contained material misstatements and omissions and seeking damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified amount and rescission. The action was transferred to the U.S. District Court for the Western District of Oklahoma on October 13, 2009. On September 2, 2010, the court denied the defendants’ motion to dismiss, and on August 1, 2011, the plaintiffs filed a motion for class certification. Discovery in the case is proceeding. We are currently unable to assess the probability of loss or estimate a range of potential loss associated with the case. A derivative action was also filed in the District Court of Oklahoma County, Oklahoma on March 10, 2009 against certain current and former directors and officers of the Company asserting breaches of fiduciary duties relating to alleged material omissions in the registration statement for the July 2008 offering. The derivative action is stayed pursuant to stipulation. A second derivative action relating to the July 2008 offering was filed against certain current and former directors and officers of the Company in the U.S. District Court for the Western District of Oklahoma on September 6, 2011. This action also asserts breaches of fiduciary duties with respect to alleged material omissions in the offering registration statement. The Company filed a motion to dismiss the action on November 30, 2011, and plaintiffs filed an Opposition on January 9, 2012. Chesapeake is named as a nominal defendant in both derivative actions.

 

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Three derivative actions were filed in the District Court of Oklahoma County, Oklahoma on April 28, May 7, and May 20, 2009 against the Company’s directors alleging, among other things, breaches of fiduciary duties relating to the 2008 compensation of the Company’s CEO, Aubrey K. McClendon, and seeking unspecified damages, equitable relief and disgorgement. These three derivative actions were consolidated and a Consolidated Derivative Shareholder Petition naming Chesapeake as a nominal defendant was filed on June 23, 2009. Chesapeake’s motion to dismiss was granted on February 26, 2010, and the Oklahoma Court of Civil Appeals affirmed the dismissal on August 26, 2011. The plaintiffs filed a petition for writ of certiorari with the Oklahoma Supreme Court on September 13, 2011.

On January 30, 2012, the District Court of Oklahoma County, Oklahoma approved the settlement between the parties in the consolidated derivative action, as well as a case on appeal at the Oklahoma Court of Civil Appeals requesting inspection of Company books and records relating to the December 2008 employment agreement with its CEO. The principal terms of the settlement include the rescission of the sale of an antique map collection that occurred in December 2008 between Mr. McClendon and the Company, whereby Mr. McClendon will pay the Company $12.1 million plus interest and the Company will reconvey the map collection to Mr. McClendon, and the adoption and/or implementation of a variety of corporate governance measures. The court awarded attorney fees and expenses to plaintiffs’ counsel in the amount of $3,750,000, to be paid by Chesapeake and/or its insurers. Pursuant to the settlement, the consolidated derivative action and books and records action were dismissed with prejudice against all defendants.

On September 6 and 8, 2011, in separate derivative actions filed in the U.S. District Court for the Western District of Oklahoma against certain of the Company’s current and former directors, two shareholders alleged that the Chesapeake board wrongfully refused their demands to investigate purported breaches of fiduciary duties relating to Mr. McClendon’s 2008 compensation and, as a result, each of these shareholders asserts he is entitled to seek relief on behalf of the Company. These federal derivative actions were consolidated on December 23, 2011 and were stayed pending final approval of the state court settlement. On February 7, 2012, the Court entered an order deferring defendants’ response to the complaint until March 6, 2012.

Chesapeake is also involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, claims for underpayment of royalties, property damage claims and contract actions. With regard to the latter, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their natural gas and oil interests and pay acreage bonus payments, damages based on breach of contract and/or, in certain cases, punitive damages based on alleged fraud. The Company has successfully defended a number of these cases in various courts, has settled others and believes that it has substantial defenses to the claims made in those pending at the trial court and on appeal.

The Company records an associated liability when a loss is probable and the amount is reasonably estimable. Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute incidental to the Company’s business operations is likely to have a material adverse effect on its consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.

Environmental Proceedings

The Pennsylvania Department of Environmental Protection (DEP) issued a notice of violation following a well control incident in Bradford County, Pennsylvania on April 19, 2011. Chesapeake took several actions in response to the incident, including voluntarily suspending well completion operations in the state and conducting wellhead inspections on other wells in the completion phase in the

 

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Marcellus Shale. With the concurrence of the DEP, we resumed well completion operations in mid-May 2011, and we implemented responsive measures to address issues identified in investigations of the incident conducted by us and the DEP. Our investigation found that, while a small amount of well fluid and rain water was released from the containment area of the well location, the impact to the environment from this release was minimal and localized. An independent consulting firm retained by Chesapeake filed multiple reports with the DEP concluding that there were no ecological impacts to nearby tributaries, no impacts to nearby or regional water wells or springs and no subsurface release of fluids or natural gas from the well control incident. Under a Consent Order and Agreement (COA) dated February 3, 2012 between Chesapeake and the DEP, in settlement of the DEP’s claim for civil penalties relating to the incident, Chesapeake paid $123,000 in civil penalties assessed under the Pennsylvania Oil and Gas Act and the Clean Streams Law and agreed to conduct additional shallow groundwater sampling at five monitoring wells surrounding the well site over the course of a year, the last sampling to occur in the spring of 2012. In addition, Chesapeake reimbursed the DEP for costs and expenses associated with the DEP’s response to the well control incident in the amount of $67,000.

Under a COA also dated February 3, 2012 between Chesapeake and the DEP, in settlement of the DEP’s claim for civil penalties relating to soil erosion and encroachment of a forested wetland associated with the construction of a well pad, Chesapeake paid $160,000 assessed by the DEP under the Pennsylvania Clean Streams Law and Dam Safety and Encroachments Act. In addition, pursuant to the COA, Chesapeake will take certain corrective actions to implement a planting plan and a wetland mitigation plan approved by the DEP.

Under a Consent Assessment of Civil Penalty dated February 3, 2012, in resolution of the DEP’s claim for civil penalties under the Clean Streams Law in connection with erosion and sediment control associated with a pad site, Chesapeake paid a civil penalty and costs in the amount of $215,000. Chesapeake also corrected the issues identified in the DEP’s March 2011 compliance order and reimbursed a local water authority for costs incurred as a result of sediment contained in runoff from the pad.

In addition, there are pending against us orders for compliance issued by the West Virginia Department of Environmental Protection (WVDEP) related to alleged violations of the West Virginia Dam Control and Safety Act at four structures constructed for Chesapeake in West Virginia. We have responded to the orders for compliance and continue to work with the WVDEP to resolve the matter. Although we cannot estimate the amount of any monetary sanctions, resolution of these compliance orders can reasonably be expected to include monetary sanctions in excess of $100,000.

There are also outstanding orders for compliance initiated in the 2010 fourth quarter by the U.S. Environmental Protection Agency (EPA) related to our compliance with Clean Water Act (CWA) permitting requirements in West Virginia. We have responded to all pending orders and are actively working with the EPA to resolve these matters. For four of the sites subject to EPA orders for compliance, we have received and have responded to a subpoena requesting documents issued by the grand jury of the U.S. District Court for the Northern District of West Virginia. We understand that the U.S. Department of Justice (DOJ) is investigating possible criminal violations of and liabilities under the CWA with respect to three of the four sites. We are cooperating with the DOJ’s investigation. The CWA provides authority for significant civil and criminal penalties for the placement of fill in a jurisdictional stream or wetland without a permit from the Army Corps of Engineers. CWA civil penalties can be as high as $37,500 per day, per violation, and possible criminal penalties range from $2,500 to $25,000 per day, per violation, for misdemeanor liability (i.e., criminally negligent conduct) and from $5,000 to $50,000 per day, per violation, for felony liability (i.e., knowing conduct). The CWA sets forth subjective criteria, including degree of fault and history of prior violations, that influence CWA penalty assessments, and the EPA may also seek to recover the economic benefit derived from non-compliance.

 

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The duration and outcome of the DOJ’s investigation are uncertain and the status of the investigation and our assessment of its potential impact may change as the investigation unfolds on a timetable that we cannot confidently predict and that may be affected by developments over the next few quarters. We believe that resolution of the EPA’s compliance orders and the DOJ’s investigation will each include monetary sanctions exceeding $100,000 but are unable to estimate the amount of any fines that might be imposed in these matters.

 

ITEM 4. Mine Safety Disclosures

Not applicable.

 

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Part II

 

ITEM 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Price Range of Common Stock and Dividends

Our common stock trades on the New York Stock Exchange under the symbol “CHK”. The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock as reported by the New York Stock Exchange and the amount of cash dividends declared per share:

 

     Common Stock      Dividend
Declared
 
     High      Low     

Year ended December 31, 2011:

        

Fourth Quarter

   $     29.87       $     22.00       $     0.0875   

Third Quarter

   $ 35.75       $ 25.54       $ 0.0875   

Second Quarter

   $ 34.70       $ 27.28       $ 0.0875   

First Quarter

   $ 35.95       $ 25.93       $ 0.0750   

Year ended December 31, 2010:

        

Fourth Quarter

   $ 26.43       $ 20.97       $ 0.0750   

Third Quarter

   $ 23.00       $ 19.68       $ 0.0750   

Second Quarter

   $ 25.55       $ 19.62       $ 0.0750   

First Quarter

   $ 29.22       $ 22.10       $ 0.0750   

At February 22, 2012, there were approximately 2,200 holders of record of our common stock and approximately 436,600 beneficial owners.

While we expect to continue to pay dividends on our common stock, the payment of future cash dividends is subject to the discretion of our Board of Directors and will depend upon, among other things, our financial condition, our funds from operations, the level of our capital and development expenditures, our future business prospects, contractual restrictions and other factors considered relevant by the Board of Directors.

In addition, our corporate revolving bank credit facility contains a restriction on our ability to declare and pay cash dividends on our common or preferred stock if an event of default has occurred. The certificates of designation for our preferred stock prohibit payment of cash dividends on our common stock unless we have declared and paid (or set apart for payment) full accumulated dividends on the preferred stock.

 

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Purchases of Common Stock

The following table presents information about repurchases of our common stock during the three months ended December 31, 2011:

 

Period        

   Total Number
of Shares
Purchased(a)
     Average
Price Paid
Per Share(a)
     Total
Number of
Shares
Purchased
as Part of
Publicly
Announced
Plans or
Programs
     Maximum
Number of
Shares That
May Yet Be
Purchased
Under the
Plans or
Programs(b)
 

October 1, 2011 through
October 31, 2011

     49,091       $ 26.97                   

November 1, 2011 through
November 30, 2011

     23,170       $ 25.59                   

December 1, 2011 through
December 31, 2011

     60,574       $ 22.47                   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     132,835       $ 24.68                   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(a)

Reflects the surrender to the Company of shares of common stock to pay withholding taxes in connection with the vesting of employee restricted stock.

 

(b)

We make matching contributions to our 401(k) plan and deferred compensation plan using Chesapeake common stock which is held in treasury or is purchased by the respective plan trustees in the open market. The plans contain no limitation on the number of shares that may be purchased for the purposes of the Company contributions.

 

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ITEM 6. Selected Financial Data

The following table sets forth selected consolidated financial data of Chesapeake for the years ended December 31, 2011, 2010, 2009, 2008 and 2007. The data are derived from our audited consolidated financial statements revised to reflect the reclassification of certain items. 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, respectively, of this report.

 

     Years Ended December 31,  
     2011     2010     2009     2008     2007  

STATEMENT OF OPERATIONS DATA:

     ($ in millions, except per share data)   

REVENUES:

          

Natural gas and oil

   $ 6,024      $ 5,647      $ 5,049      $ 7,858      $ 5,624   

Marketing, gathering and compression

     5,090        3,479        2,463        3,598        2,040   

Oilfield services

     521        240        190        173        136   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Revenues

     11,635        9,366        7,702        11,629        7,800   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

OPERATING EXPENSES:

          

Natural gas and oil production

     1,073        893        876        889        640   

Production taxes

     192        157        107        284        216   

Marketing, gathering and compression

     4,967        3,352        2,316        3,505        1,969   

Oilfield services

     402        208        182        143        94   

General and administrative

     548        453        349        377        243   

Natural gas and oil depreciation, depletion and amortization

     1,632        1,394        1,371        1,970        1,835   

Depreciation and amortization of other assets

     291        220        244        174        153   

(Gains) losses on sales and impairments of fixed assets

     (391     (116     168        30          

Impairment of natural gas and oil properties

                   11,000        2,800          

Restructuring

                   34                 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Expenses

     8,714        6,561        16,647        10,172        5,150   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

INCOME (LOSS) FROM OPERATIONS

     2,921        2,805        (8,945     1,457        2,650   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

OTHER INCOME (EXPENSE):

          

Interest expense

     (44     (19     (113     (271     (401

Earnings (losses) on investments

     156        227        (39     (38       

Losses on purchases or exchanges of debt

     (176     (129     (40     (4       

Impairments of investments

            (16     (162     (180       

Other income

     23        16        11        27        15   

Gain on sale of investments

                                 83   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Other Income (Expense)

     (41     79        (343     (466     (303
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

INCOME (LOSS) BEFORE INCOME TAXES

     2,880        2,884        (9,288     991        2,347   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

INCOME TAX EXPENSE (BENEFIT):

          

Current income taxes

     13               4        423        29   

Deferred income taxes

     1,110        1,110        (3,487     (36     863   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Income Tax Expense (Benefit)

     1,123        1,110        (3,483     387        892   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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     Years Ended December 31,  
     2011     2010     2009     2008     2007  
     ($ in millions, except per share data)  

STATEMENT OF OPERATIONS DATA (continued):

          

NET INCOME (LOSS)

     1,757        1,774        (5,805     604        1,455   

Net income attributable to noncontrolling interests

     (15            (25              
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE

     1,742        1,774        (5,830     604        1,455   

Preferred stock dividends

     (172     (111     (23     (33     (94

Loss on conversion/exchange of preferred stock

                          (67     (128
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS

   $ 1,570      $ 1,663      $ (5,853   $ 504      $ 1,233   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EARNINGS (LOSS) PER COMMON SHARE:

          

Basic

   $ 2.47      $ 2.63      $ (9.57   $ 0.94      $ 2.70   

Diluted

   $ 2.32      $ 2.51      $ (9.57   $ 0.93      $ 2.63   

CASH DIVIDENDS DECLARED PER COMMON SHARE

   $ 0.3375      $ 0.30      $ 0.30      $ 0.2925      $ 0.2625   

CASH FLOW DATA:

          

Cash provided by operating activities

   $ 5,903      $ 5,117      $ 4,356      $ 5,357      $ 4,974   

Cash used in investing activities

   $ 5,812      $ 8,503      $ 5,462      $ 9,965      $ 7,964   

Cash provided by (used in) financing activities

   $ 158      $ 3,181      $ (336   $ 6,356      $ 2,988   

BALANCE SHEET DATA
(AT END OF PERIOD):

          

Total assets

   $ 41,835      $ 37,179      $ 29,914      $ 38,593      $ 30,764   

Long-term debt, net of current maturities

   $ 10,626      $ 12,640      $ 12,295      $ 13,175      $ 10,178   

Total equity

   $ 17,961      $ 15,264      $ 12,341      $ 17,017      $ 12,624   

 

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

Financial Data

The following table sets forth certain information regarding the production volumes, natural gas and oil sales, average sales prices received, other operating income and expenses for the periods indicated:

 

     Years Ended December 31,  
         2011             2010             2009      

Net Production:

      

Natural gas (bcf)

     1,004.1        924.9        834.8   

Oil (mmbbl)(a)

     31.7        18.4        11.8   

Natural gas equivalent (bcfe)(b)

     1,194.2        1,035.2        905.5   

Natural Gas and Oil Sales ($ in millions):

      

Natural gas sales

   $ 3,133      $ 3,169      $ 2,635   

Natural gas derivatives – realized gains (losses)

     1,656        1,982        2,313   

Natural gas derivatives – unrealized gains (losses)

     (669     425        (492
  

 

 

   

 

 

   

 

 

 

Total natural gas sales

     4,120        5,576        4,456   
  

 

 

   

 

 

   

 

 

 

Oil sales(a)

     2,126        1,079        656   

Oil derivatives – realized gains (losses)

     (102     74        33   

Oil derivatives – unrealized gains (losses)

     (120     (1,082     (96
  

 

 

   

 

 

   

 

 

 

Total oil sales

     1,904        71        593   
  

 

 

   

 

 

   

 

 

 

Total natural gas and oil sales

   $ 6,024      $ 5,647      $ 5,049   
  

 

 

   

 

 

   

 

 

 

Average Sales Price (excluding gains (losses) on derivatives):

      

Natural gas ($ per mcf)

   $ 3.12      $ 3.43      $ 3.16   

Oil ($ per bbl)(a)

   $ 67.11      $ 58.67      $ 55.60   

Natural gas equivalent ($ per mcfe)

   $ 4.40      $ 4.10      $ 3.63   

Average Sales Price (excluding unrealized gains (losses) on derivatives):

      

Natural gas ($ per mcf)

   $ 4.77      $ 5.57      $ 5.93   

Oil ($ per bbl)(a)

   $ 63.90      $ 62.71      $ 58.38   

Natural gas equivalent ($ per mcfe)

   $ 5.70      $ 6.09      $ 6.22   

Other Operating Income(c) ($ in millions):

      

Marketing, gathering and compression net margin

   $ 123      $ 127      $ 147   

Oilfield services net margin

   $ 119      $ 32      $ 8   

Other Operating Income(c) ($ per mcfe):

      

Marketing, gathering and compression net margin

   $ 0.10      $ 0.12      $ 0.16   

Oilfield services net margin

   $ 0.10      $ 0.03      $ 0.01   

Expenses ($ per mcfe):

      

Production expenses

   $ 0.90      $ 0.86      $ 0.97   

Production taxes

   $ 0.16      $ 0.15      $ 0.12   

General and administrative expenses

   $ 0.46      $ 0.44      $ 0.38   

Natural gas and oil depreciation, depletion and amortization

   $ 1.37      $ 1.35      $ 1.51   

Depreciation and amortization of other assets

   $ 0.24      $ 0.21      $ 0.27   

Interest expense(d)

   $ 0.03      $ 0.08      $ 0.22   

Interest Expense ($ in millions):

      

Interest expense(d)

   $ 30      $ 99      $ 227   

Interest rate derivatives – realized (gains) losses

     7        (14     (23

Interest rate derivatives – unrealized (gains) losses

     7        (66     (91
  

 

 

   

 

 

   

 

 

 

Total interest expense

   $ 44      $ 19      $ 113   
  

 

 

   

 

 

   

 

 

 

 

(a)

Includes NGLs.

 

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(b)

Natural gas equivalent is based on six mcf of natural gas to one barrel of oil. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given recent commodity prices, the price for an mcfe of natural gas is significantly less than the price for an mcfe of oil or NGLs.

 

(c)

Includes revenue and operating costs and excludes depreciation and amortization of other assets.

 

(d)

Includes the effects of realized (gains) losses from interest rate derivatives, but excludes the effects of unrealized (gains) losses and is net of amounts capitalized.

We manage our business as three separate operational segments: exploration and production; marketing, gathering and compression; and oilfield services. We refer you to Note 17 of the notes to our consolidated financial statements in Item 8 of this report, which summarizes by segment our net income and capital expenditures for 2011, 2010 and 2009 and our assets as of December 31, 2011, 2010 and 2009.

Executive Summary

We are the second-largest producer of natural gas, a top 15 producer of liquids and the most active driller of new wells in the U.S. We own interests in approximately 45,700 producing natural gas and oil wells that are currently producing approximately 3.5 bcfe per day, net to our interest. The Company has built a large resource base of onshore U.S. natural gas assets in the Haynesville and Bossier Shales in northwestern Louisiana and East Texas; the Marcellus Shale in the northern Appalachian Basin of West Virginia and Pennsylvania; the Barnett Shale in the Fort Worth Basin of north-central Texas; and the Pearsall Shale in South Texas. In addition, we have built leading positions in the liquids-rich resource plays of the Eagle Ford Shale in South Texas; the Utica Shale in Ohio and Pennsylvania; the Granite Wash, Cleveland, Tonkawa and Mississippi Lime plays in the Anadarko Basin in western Oklahoma and the Texas Panhandle; the Bone Spring, Avalon, Wolfcamp and Wolfberry plays in the Permian and Delaware Basins in West Texas and southern New Mexico; and the Niobrara Shale in the Powder River Basin in Wyoming. We have also vertically integrated many of our operations and own substantial midstream, compression and oilfield services assets as discussed under Business Strategy in Item 1.

Proved Reserves. Chesapeake began 2011 with estimated proved reserves of 17.096 tcfe and ended with 18.789 tcfe as of December 31, 2011, an increase of 1.693 tcfe, or 10%. The 2011 proved reserve movement included 1.194 tcfe of production, 5.683 tcfe of extensions, 64 bcfe of negative performance revisions to previous estimates and 14 bcfe of positive revisions resulting from higher oil prices using the average first-day-of-the-month price for the twelve months ended December 31, 2011, compared to the twelve months ended December 31, 2010. During 2011, we acquired 30 bcfe of estimated proved reserves and divested 2.776 tcfe of estimated proved reserves, including the disposition of 2.420 tcfe associated with the sale of our Fayetteville Shale assets in March 2011 (as described below under Steps Taken in 2011 to Implement Our Business Strategy). The 64 bcfe of negative revisions to previous estimates consisted of 337 bcfe of negative revisions associated with the deletion of PUDs no longer consistent with our development plans, offset by 273 bcfe of positive revisions to producing properties and proved undeveloped reserves estimates.

Drilling and Completion Expenditures. During 2011, we invested $6.036 billion in operated wells (using an average of 167 operated rigs) and $1.509 billion in non-operated wells (using an average of 97 non-operated rigs) for total drilling and completing costs on proved and unproved properties of $7.545 billion, net of drilling and completion carries of $2.570 billion.

Production. Our total 2011 production of 1.194 tcfe consisted of 1.004 tcf of natural gas (84% on a natural gas equivalent basis) and 31.676 mmbbls of liquids (16% on a natural gas equivalent basis). Daily production for 2011 averaged 3.272 bcfe, an increase of 436 mmcfe, or 15%, over the 2.836 bcfe produced per day in 2010. This was our 22nd consecutive year of sequential production growth.

 

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In 2012, Chesapeake has curtailed its natural gas production approximately 1.0 bcf per day of gross operated natural gas production, or approximately 1.5% of U.S. lower 48 natural gas production, in response to continued low natural gas prices and as an effort to help bring U.S. natural gas supply and demand into better balance. The curtailed volumes are located primarily in the Haynesville and Barnett shale plays. In addition, wherever possible, the company is deferring completions of dry gas wells that have been drilled, but not yet completed, and is also deferring pipeline connections of dry gas wells that have already been completed. As a result of production curtailments and reduced drilling and completion activity, partially offset by growth in associated natural gas production in liquids-rich plays, Chesapeake projects that its 2012 net natural gas production will average approximately 2.65 bcf per day, a decrease of 100 mmcf per day, or 4%, compared to the Company’s 2011 average net natural gas production of 2.75 bcf per day.

Leasehold and Seismic Inventories. Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (15.3 million net acres) and 3-D seismic (30.8 million acres) in the U.S. We have accumulated the largest inventory of U.S. natural gas shale play leasehold (2.2 million net acres) and own a leading position in 11 of what we believe are the top 15 unconventional liquids-rich plays in the U.S. We are currently using 161 operated drilling rigs to further develop our inventory of approximately 39,200 net drillsites. The company is targeting to invest approximately $1.4 billion in net undeveloped leasehold expenditures in 2012, of which approximately 90% will be in liquids-rich plays and 100% will be in plays where the company is already active. This compares to net undeveloped leasehold expenditures of approximately $3.5 billion and $5.8 billion in 2011 and 2010, respectively.

Emphasis on Increasing Liquids Production. In recognition of the value gap between liquids and natural gas prices, Chesapeake has directed a significant portion of its technological and leasehold acquisition expertise during the past three years to identify, secure and commercialize new unconventional liquids-rich plays. This planned transition will result in a more balanced and likely more profitable portfolio between natural gas and liquids. To date, we have built leasehold positions and established production in multiple liquids-rich plays on approximately 6.6 million net acres with 830 million bbls of oil equivalent of proved reserves. Our production of liquids averaged 86,784 bbls per day during 2011, a 72% increase over the average during 2010, as a result of the increased development of our unconventional liquids-rich plays. We are projecting that the portion of our operated drilling and completion expenditures allocated to liquids development will reach 85% in 2012, and we expect to increase our liquids production through our drilling activities to an average of approximately 150,000 bbls per day in 2012 and to more than 200,000 bbls per day in 2013 and 250,000 bbls per day by 2015.

Other Operational Segments. In addition to our exploration and production operational segment, we also have a marketing, gathering and compression operational segment and an oilfield services operational segment that we utilize as a financial and operational hedge against inflation and to assure that we have access to quality services. In October 2011, we formally segregated our oilfield services businesses under our wholly owned subsidiary, COS, and its wholly owned subsidiary COO. COO’s subsidiaries include a leading U.S. drilling contractor, oilfield trucking company, oilfield rental tool provider and a developing pressure pumping business. In September 2009, we formally segregated our midstream gathering services under a wholly owned subsidiary, CMD, and it has engaged in significant sales transactions with our affiliate midstream master limited partnership. These segments are separately capitalized, each with its own revolving bank credit facility, and COO issued senior notes in 2011.

 

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Steps Taken in 2011 to Implement Our Business Strategy

Our business strategy is to create value for investors by building and developing one of the largest onshore natural gas and liquids resource bases in the U.S. The key elements of our business strategy, as described in Business Strategy in Item 1, are the following:

 

   

growing production and proved reserves through the drillbit;

 

   

controlling substantial land and drilling location inventories and building operating focus and scale;

 

   

developing proprietary technological advantages;

 

   

focusing on achieving low costs through our focused activities, vertical integration and increasing scale;

 

   

mitigating natural gas and oil price risk through our hedging program;

 

   

entering into value-creating joint ventures;

 

   

improving our balance sheet through reduction of debt;

 

   

transforming the U.S. transportation fuels market and increasing demand for U.S. natural gas; and

 

   

maintaining an entrepreneurial culture.

Below we describe significant activities in 2011 that evidence our commitment to our business strategy.

Joint Ventures. In February 2011, we entered into a joint venture with a wholly owned subsidiary of CNOOC Limited (CNOOC) to sell a 33.3% undivided interest in approximately 800,000 net acres of leasehold overlaying the Niobrara Shale, Codell Sand and various other formations in the Powder River and DJ basins in northeast Colorado and southeast Wyoming. Under the terms of the joint venture, we received $570 million in cash at closing, and CNOOC has agreed to fund 66.7% of our share of drilling and completion costs until an additional $697 million has been paid, which we expect to occur by year-end 2014. CNOOC has the right to a 33.3% participation in any additional leasehold we acquire in the joint venture area of mutual interest at cost plus a fee.

In December 2011, we entered into a joint venture with Total E&P, USA, Inc., a wholly owned subsidiary of Total S.A. (Total), in the liquids-rich area of the Utica Shale. Under the terms of the joint venture, Total acquired an undivided 25% interest in approximately 619,000 net acres of leasehold, of which Chesapeake contributed approximately 542,000 net acres and Enervest, Ltd. contributed approximately 77,000 net acres to the joint venture, covering all or a portion of 10 counties in eastern Ohio. We received approximately $610 million in cash at closing and approximately $1.42 billion will be paid in the form of a drilling and completion cost carry, which we anticipate fully receiving by year-end 2014. In addition, Total will acquire a 25% share in any additional acreage we acquire in the joint venture area of mutual interest at cost plus a fee.

As of December 31, 2011, including the joint ventures described above, we had entered into seven significant joint ventures with other leading energy companies pursuant to which we sold a portion of our leasehold, producing properties and other assets located in seven different resource plays and received cash of $7.1 billion and commitments for future drilling and completion cost sharing of $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all

 

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leasing, drilling, completion, operations and marketing activities for the project. These transactions have allowed us to recover much or all of our initial leasehold investments and reduce our ongoing capital costs in these plays. The transactions are detailed below.

 

Primary

Play

  Joint
Venture
Partner(a)
 

Joint
Venture Date

  Interest
Sold
    Cash
Proceeds
Received
at
Closing
    Total
Drilling
Carries
    Drilling
Carries
Remaining(b)
 
                  ($ in millions)  

Utica

 

TOT

 

December 2011

    25.0%      $ 610      $ 1,422      $ 1,422   

Niobrara

 

CNOOC

 

February 2011

    33.3%        570        697        570   

Eagle Ford & Pearsall

 

CNOOC

 

November 2010

    33.3%        1,120        1,080        144   

Barnett

 

TOT

 

January 2010

    25.0%        800        1,404 (c)        

Marcellus

 

STO

 

November 2008

    32.5%        1,250        2,125        223   

Fayetteville

 

BP

 

September 2008

    25.0%        1,100        800          

Haynesville & Bossier

 

PXP

 

July 2008

    20.0%        1,650        1,508 (d)        
       

 

 

   

 

 

   

 

 

 
        $     7,100      $     9,036      $     2,359   
       

 

 

   

 

 

   

 

 

 

 

(a)

Joint venture partners include Total S.A. (TOT), CNOOC Limited (CNOOC), Statoil (STO), BP America (BP) and Plains Exploration & Production Company (PXP).

 

(b)

As of December 31, 2011.

 

(c)

In conjunction with an agreement requiring us to maintain our operated rig count at no less than 12 rigs in the Barnett Shale through December 31, 2012, TOT accelerated the payment of its remaining joint venture drilling carry in exchange for an approximate 9% reduction in the total amount of drilling carry obligation owed to us at that time. As a result, in October 2011, we received $471 million in cash from TOT, which included $46 million of carry obligation billed and $425 million for the remaining carry obligation. In January 2012, Chesapeake and TOT agreed to reduce the minimum rig count from 12 to six rigs.

 

(d)

In September 2009, PXP accelerated the payment of its remaining carry in exchange for an approximate 12% reduction to the remaining drilling carry obligation owed to us at that time.

The drilling and completion carries in our joint venture agreements create a significant cost advantage that allows us to reduce our future finding costs. During 2011 and 2010, our drilling and completion costs included the benefit of approximately $2.570 billion and $1.151 billion, respectively, of drilling and completion carries. Our drilling and completion costs for 2012, 2013 and 2014 will continue to be partially offset by the use of our remaining drilling and completion carries associated with our joint venture agreements.

During 2011, as part of our joint venture agreements with CNOOC, TOT, STO and PXP, we sold interests in additional leasehold in the Niobrara, Eagle Ford and Pearsall, Barnett, Marcellus and Haynesville and Bossier shale plays for proceeds of approximately $511 million that had an estimated cost to us of approximately $311 million. The cash proceeds from these transactions are reflected as a reduction of natural gas and oil properties with no gain or loss recognized.

Fayetteville Shale Asset Monetization. In March 2011, we sold all of our Fayetteville Shale assets in central Arkansas to BHP Billiton Petroleum, a wholly owned subsidiary of BHP Billiton Limited, for net proceeds of approximately $4.65 billion in cash. The sold properties consisted of approximately 487,000 net acres of leasehold, net production at closing of approximately 415 mcfe per day and midstream assets consisting of approximately 420 miles of pipeline. As part of the transaction, we

 

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agreed to provide technical and business services for up to one year for BHP Billiton’s Fayetteville properties for an agreed-upon fee. We used a portion of the funds we received from the Fayetteville transaction to purchase outstanding debt as described below.

Purchases of Senior Debt. In May 2011, we completed tender offers to purchase $1.373 billion in aggregate principal amount of certain of our senior notes and $531 million in aggregate principal amount of certain of our contingent convertible senior notes. These tender offers were part of our plan to reduce the amount of our outstanding indebtedness by 25% in the two-year period ending December 31, 2012. We funded the purchase of the notes with a portion of the net proceeds we received from the monetization of our Fayetteville Shale assets. Combined with the $140 million in aggregate principal amount of contingent convertible senior notes we purchased in privately negotiated transactions, we retired an aggregate principal amount of $2.044 billion of senior notes and contingent convertible senior notes in 2011.

Volumetric Production Payment (VPP). In May 2011, we monetized certain of our producing assets in the Mid-Continent through a ten-year VPP for proceeds of approximately $853 million. The transaction included approximately 177 bcfe of proved reserves and approximately 80 mmcfe per day of net production. Chesapeake has retained drilling rights on the properties below currently producing intervals and outside of existing producing wellbores and we also retain all production beyond the specified volumes sold in the transaction. This transaction was our ninth VPP. The cash proceeds for this transaction were reflected as a reduction of natural gas and oil properties with no gain or loss recognized. Other VPPs we completed in 2007 – 2010 are detailed in Note 11 of the consolidated financial statements included in Item 8 of this report.

Bronco Drilling Acquisition. As an extension of our oilfield services vertical integration strategy, in June 2011 we acquired Bronco Drilling Company, Inc., a publicly traded company, for an aggregate purchase price of approximately $339 million, or $11.00 per share of Bronco common stock. The acquisition included 22 high-quality drilling rigs primarily operating in the Williston and Anadarko basins which were transferred to our drilling subsidiary, Nomac Drilling, L.L.C.

CNGV Investments. In July 2011, CNGV, a wholly owned subsidiary, made its first two investments in companies and technologies that we believe have the potential to replace the use of gasoline and diesel derived primarily from imported oil with domestic oil, natural gas and natural gas-to-liquids fuels. We agreed to invest $150 million in newly issued convertible promissory notes of Clean Energy Fuels Corp. (Nasdaq:CLNE), based in Seal Beach, California. The investment will be made in three equal $50 million promissory notes, the first of which was issued in July 2011, with the remaining notes scheduled to be issued in June 2012 and June 2013. The notes bear interest at the annual rate of 7.5%, payable quarterly, and are convertible at our option into shares of Clean Energy’s common stock at a 22.5% conversion premium, resulting in a conversion price of $15.80 per share. If certain requirements have been met following the second anniversary of the issuance of a note, Clean Energy can force conversion of the debt. The entire principal balance of each note is due and payable seven years following issuance. Clean Energy will use our $150 million investment to accelerate its build-out of LNG fueling infrastructure for heavy-duty trucks at truck stops across interstate highways in the U.S.

Also in July 2011, CNGV agreed to invest $155 million in preferred equity securities of Sundrop Fuels, Inc., a privately held cellulosic biofuels company based in Louisville, Colorado. The investment over the next two years will fund construction of a waste biomass-based “green gasoline” plant, capable of annually producing more than 40 million gallons of gasoline from natural gas and cellulosic material. The investment is intended to accelerate the development of an affordable, stable, room-temperature, natural gas-based fuel for immediate use in automobiles, diesel engine vehicles and aircraft. The first $35 million tranche of our investment was funded in July 2011 and the remaining

 

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tranches of preferred equity investment will be scheduled around certain funding and operational milestones that are expected to be reached over the next two years. The full investment will represent approximately 50% of Sundrop Fuels’ equity on a fully diluted basis.

Oilfield Services Capitalization. In October 2011, our wholly owned subsidiary, COO, issued $650 million principal amount of 6.625% Senior Notes due 2019 in a private placement. COO used a portion of the net proceeds of approximately $637 million from the placement to make a cash distribution to its direct parent, COS, to enable it to reduce indebtedness under an intercompany note with Chesapeake. Chesapeake used the cash distribution to repay outstanding indebtedness under its corporate revolving bank credit facility. In November 2011, COO established a five-year syndicated revolving bank credit facility with $500 million in total commitments (we estimate the capacity was limited to approximately $290 million as of December 31, 2011 by certain restrictive provisions). Borrowings under the credit facility are secured by liens on all of the equity interests of COO and COO’s current and future guarantor subsidiaries and all of their assets, including real and personal property.

Utica Financial Transaction. CHK Utica, L.L.C. (CHK Utica) is an unrestricted, non-guarantor consolidated subsidiary we formed in October 2011 to develop a portion of our Utica Shale natural gas and oil assets. In exchange for all of the common shares, we contributed to CHK Utica approximately 700,000 net acres of leasehold within an area of mutual interest in the Utica Shale play covering 13 counties located primarily in eastern Ohio. During November and December 2011, in private placements, third-party investors contributed $1.25 billion in cash to CHK Utica in exchange for (i) 1.25 million CHK Utica preferred shares, and (ii) our obligation to deliver a 3% overriding royalty interest (ORRI) in up to 1,500 net wells to be drilled on certain of our Utica Shale leasehold. Dividends on the preferred shares are payable on a quarterly basis at a rate of 7% per annum based on $1,000 per share. This dividend rate is subject to increase in limited circumstances in the event that, and only for so long as, cash flow from the assets owned by CHK Utica are insufficient to fund the dividend in full in any quarter. We have committed to drill, for the benefit of CHK Utica, a minimum of 50 net wells per year through 2016 in the CHK Utica area of mutual interest, up to a minimum cumulative total of 250 net wells. As the managing member of CHK Utica, we may, at our sole discretion and election at any time after December 31, 2013, distribute certain excess cash of CHK Utica. If we are current in our drilling commitment at the time, any such optional distribution of excess cash is allocated 70% to the preferred shares (which is applied toward redemption of the preferred shares) and 30% to the common shares. We may also cause CHK Utica to redeem the CHK Utica preferred shares for cash, in whole or in part, at a valuation equal to the greater of a 10% internal rate of return or a return on investment of 1.4x, in each case inclusive of dividends paid at the rate of 7% per annum and optional distributions made through the applicable redemption date. In the event that redemption does not occur on or prior to October 31, 2018, the optional redemption valuation increases to the greater of a 17.5% internal rate of return or a return on investment of 2.0x. As of December 31, 2011, the redemption price, and the liquidation preference, was $1,400 per preferred share. CHK Utica is responsible for all capital and operating costs of the wells drilled for the benefit of the entity. CHK Utica also receives its proportionate share of the benefit of the drilling carry associated with our joint venture with Total in the Utica Shale. For further discussion, see Noncontrolling Interests in Note 8 of the notes to our consolidated financial statements in Item 8 of this report.

Royalty Trust. In November 2011, the Chesapeake Granite Wash Trust (the Trust), a newly formed Delaware statutory trust, completed its initial public offering of 23,000,000 common units representing an approximate 49% beneficial interest in the Trust. Net proceeds to the Trust, after certain offering expenses, were approximately $410 million. Concurrent with the closing, we conveyed certain royalty interests to the Trust in exchange for the net proceeds of the Trust’s initial public offering and 23,750,000 units (12,062,500 common units and 11,687,500 subordinated units) representing approximately 51% of the beneficial interest in the Trust. The royalty interests conveyed by Chesapeake will entitle the Trust to a percentage of the proceeds received by Chesapeake from the production of hydrocarbons from 69 producing wells and 118 development wells to be drilled by

 

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Chesapeake by June 30, 2016 on approximately 45,400 gross acres (28,700 net acres) in the Colony Granite Wash play in Washita County in western Oklahoma. For further discussion, see Noncontrolling Interests in Note 8 of the notes to our consolidated financial statements in Item 8 of this report.

Marcellus Gathering System Sale. In December 2011, our wholly owned midstream subsidiary, CMD, sold its wholly owned subsidiary, AMS, which held substantially all of our Marcellus Shale midstream assets, to our affiliate, CHKM, for total consideration of $879 million, subject to a customary post-closing working capital adjustment. At closing, we received cash of $600 million and 9,791,605 common units of CHKM that had a value at closing of $279 million. The stock consideration increased our ownership in CHKM from 42.3% to 46.1%. The assets sold included an approximate 47% ownership of an integrated system of assets that consist of 200 miles of pipeline in the Marcellus Shale. In addition, CMD has committed to pay CHKM any quarterly shortfall between the actual EBITDA from the assets sold and specified quarterly targets, which total $100 million in 2012 and $150 million in 2013. We, and other producers in the area, have 15-year fixed fee gathering and compression agreements with AMS that include significant acreage dedications and an annual fee redetermination.

Capital Expenditures

Our exploration, development and acquisition activities require us to make substantial capital expenditures. Our current budgeted drilling and completion expenditures, net of drilling and completion carries, are $7.0 – $7.5 billion in 2012, compared to $7.5 billion in 2011. Our operated dry gas drilling expenditures in 2012, net of drilling and completion cost carries, are expected to decrease to $0.9 billion, a decrease of approximately 70% from similar expenditures of $3.1 billion in 2011 and the Company’s lowest expenditures on dry gas plays since 2005. We are projecting that the portion of our operated drilling and completion expenditures allocated to liquids development will reach 85% in 2012.

Our projected 2012 capital expenditures for our growing midstream and oilfield services businesses are $2.5 – $3.5 billion, and we are targeting to invest approximately $1.4 billion in net undeveloped leasehold expenditures in 2012, of which approximately 90% will be in liquids-rich plays and 100% will be in plays where the Company is already active. This compares to net undeveloped leasehold expenditures of approximately $3.5 billion and $5.8 billion in 2011 and 2010, respectively.

Liquidity and Capital Resources

Liquidity Overview

As discussed in Recent Developments, in Item 1, we anticipate funding our 2012 drilling and completion expenditures, and other capital expenditures, including leasehold acquisitions, using a combination of cash flow from operations and proceeds from asset monetizations, including joint ventures, volumetric production payments, financial transactions and other property and investment dispositions in 2012. In addition, since early 2011, it has been our plan to reduce our long-term debt to no more than $9.5 billion at December 31, 2012, a 25% reduction from year-end 2010, and increase our production by 25% during the two years ended December 31, 2012.

 

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We expect that the proceeds from our 2012 planned monetization transactions, which we estimate could be $10 – $12 billion, will be sufficient to fund our budgeted capital expenditures, meet our long-term debt reduction plans by year-end 2012 and provide additional liquidity for 2013. We are also projecting that our increasing liquids production will enable us to reach equilibrium between our cash flow from operations and planned drilling and completion expenditures in 2014. We do not have binding agreements for any of these transactions, however, and our ability to consummate each of them is subject to changes in market conditions and other factors. As a result, there can be no assurance that we will complete any of the announced transactions on a timely basis or at all. If we are unable to consummate these transactions or if they do not generate the proceeds we are anticipating, we would be required to seek funds from other sources. Our ability to obtain capital from asset monetizations is dependent upon many factors, and they may be beyond our control. If our access to alternative asset monetizations were limited, we could be required to reduce our capital spending, which could reduce our ability to develop and replace our reserves.

Through the vertical integration of our business and as operator of a substantial number of our properties under development, we retain significant control and flexibility over the development plan and the associated timing, which we believe is instrumental to our business plan and strategy. While our capital raising activities enabled us to fund our capital program in 2011 and pursue our goal of long-term debt reduction, certain recent transactions require us to meet performance obligations and we have significant other contractual cash obligations to third parties pursuant to various lease arrangements, gathering, processing, and transportation agreements, drilling commitments, leasehold maintenance arrangements, fleet utilization agreements, and investments in new ventures (see Note 4 of the notes to our consolidated financial statements included in Item 8 of this report). While our business plan assumes that we will meet these commitments in the ordinary course of business, we are required to meet our performance and payment obligations regardless of whether our business plan changes for circumstances beyond our control.

Sources of Funds

Cash flow from operations is a significant source of liquidity we use to fund capital expenditures, pay dividends and repay debt. Cash provided by operating activities was $5.903 billion in 2011, compared to $5.117 billion in 2010 and $4.356 billion in 2009. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items such as depreciation, depletion and amortization, deferred income taxes, mark-to-market changes in our derivative instruments and gains or losses on the sales and impairments of fixed assets. See the discussion below under Results of Operations.

Changes in market prices for natural gas and oil directly impact our cash flow from operations. To mitigate the risk of declines in natural gas and oil prices and to provide more predictable future cash flow from operations, we have entered into various derivative instruments. As natural gas and oil prices dip and reach supportable low prices, however, we may take the opportunity to close out open swap positions in order to lock in substantial mark-to-market gains. For example, during 2011, we elected to close all our natural gas swap positions thereby locking in approximately $353 million of gains for 2012 and positioning us to be able to react to market increases in the future by potentially adding new positions, although also exposing us to declining prices if we are unhedged. Our natural gas and oil derivatives as of December 31, 2011 are detailed in Item 7A of this report. Depending on changes in natural gas and oil futures markets and management’s view of underlying natural gas and oil supply and demand trends, we may increase or decrease our current derivative positions.

Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivative is deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows. In 2011, 2010 and 2009, we received $1.043 billion, $621 million and $109 million, respectively, for settlements of derivatives which were classified as cash flows from financing activities.

 

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Our $4.0 billion corporate revolving bank credit facility, our $600 million midstream revolving bank credit facility (which we estimate was limited to approximately $280 million as of December 31, 2011), our $500 million oilfield services revolving bank credit facility (which we estimate was limited to approximately $290 million as of December 31, 2011) and cash and cash equivalents are other sources of liquidity. We use the credit facilities and cash on hand to fund daily operating activities and capital expenditures as needed. We borrowed $15.509 billion and repaid $17.466 billion in 2011, we borrowed $15.117 billion and repaid $13.303 billion in 2010 and we borrowed $7.761 billion and repaid $9.758 billion in 2009 from our revolving bank credit facilities. Our corporate facility is secured by natural gas and oil proved reserves. A significant portion of our natural gas and oil reserves are currently unencumbered and therefore available to be pledged as additional collateral if needed to respond to borrowing base and collateral redeterminations our lenders might make in the future. Accordingly, we believe our borrowing capacity under this facility will not be reduced as a result of any such future redeterminations. Our midstream facility is secured by substantially all of our wholly owned midstream assets and is not subject to periodic borrowing base redeterminations. Our oilfield services facility is secured by liens on all of the equity interests of COO and COO’s current and future guarantor subsidiaries and all of their assets and is not subject to periodic borrowing base redeterminations. Our revolving bank credit facilities are described below under Bank Credit Facilities.

The following table reflects the proceeds from sales of securities we issued in 2011, 2010 and 2009:

 

     2011      2010      2009  
     Total
Proceeds
     Net
Proceeds
     Total
Proceeds
     Net
Proceeds
     Total
Proceeds
     Net
Proceeds
 
     ($ in millions)  

Senior notes(a)

   $ 1,650       $ 1,614       $ 2,000       $ 1,967       $ 1,425       $ 1,346   

Convertible preferred stock

                     2,600         2,562                   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 1,650       $ 1,614       $ 4,600       $ 4,529       $ 1,425       $ 1,346   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a)

2011 included $650 million principal amount of 6.625% Senior Notes due 2012 issued by COO for net proceeds of $637 million.

The following table reflects proceeds we received from our significant natural gas and oil asset monetizations in 2011, 2010 and 2009:

 

     2011      2010      2009  
     ($ in millions)  

Natural gas and oil property monetizations:

        

TOT (Utica) joint venture

   $ 610       $       $   

CNOOC (Niobrara) joint venture(a )

     619                   

CNOOC (Eagle Ford) joint venture(b )

     201         1,085           

TOT (Barnett) joint venture(c )

     490         891           

STO (Marcellus) joint venture(d )

     165         389         9   

PXP (Haynesville) joint venture(e )

     14         16         1,129   

BHP (Fayetteville) divestiture

     4,270                   

Volumetric production payments

     849         1,622         408   

Other divestitures

     433         289         380   
  

 

 

    

 

 

    

 

 

 

Total

   $ 7,651       $ 4,292       $ 1,926   
  

 

 

    

 

 

    

 

 

 

 

(a)

2011 includes $66 million in proceeds from sales of additional acreage in the Niobrara area of mutual interest to CNOOC.

 

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(b)

2011 includes proceeds from sales of additional acreage in the Eagle Ford area of mutual interest to CNOOC.

 

(c)

2011 and 2010 include $65 million and $38 million in proceeds, respectively, for sales of additional acreage in the Barnett area of mutual interest to TOT. In addition, 2011 includes the $425 million acceleration of the payment of TOT’s remaining drilling carry in exchange for a reduction in the obligation. See Note 11 in Item 8 of this report for further discussion.

 

(d)

2011, 2010 and 2009 amounts for sales of additional acreage in the Marcellus area of mutual interest to STO.

 

(e)

2011 and 2010 amounts for proceeds from sales of additional acreage in the Haynesville area of mutual interest to PXP. 2009 includes the acceleration of the payment of PXP’s remaining drilling carry in exchange for a reduction in the obligation. See Note 11 in Item 8 of this report for further discussion.

In December 2011, our wholly owned midstream subsidiary, CMD sold substantially all of its natural gas gathering systems and related facilities in the Marcellus Shale through the sale of its subsidiary, AMS, to CHKM for total consideration of $879 million. The $879 million consisted of $279 million in CHKM common units and $600 million cash.

In November 2011 and December 2011, third-party investors contributed $1.25 billion in cash to CHK Utica, L.L.C. in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3% overriding royalty interest in up to 1,500 net wells to be drilled on certain of our Utica Shale leasehold. CHK Utica, L.L.C. is an unrestricted, non-guarantor consolidated subsidiary we formed in October 2011 to develop a portion of our Utica Shale natural gas and oil assets.

In November 2011, the Chesapeake Granite Wash Trust (the Trust), a newly formed Delaware statutory trust, completed its initial public offering of 23,000,000 common units representing an approximate 49% beneficial interest in the Trust. Net proceeds to the Trust, after certain offering expenses, were approximately $410 million. Concurrent with the closing, we conveyed certain royalty interests to the Trust in exchange for the net proceeds of the Trust’s initial public offering and 23,750,000 units (12,062,500 common units and 11,687,500 subordinated units) representing approximately 51% of the beneficial interest in the Trust.

In December 2010, CMD sold its Springridge natural gas gathering system and related facilities in the Haynesville Shale to CHKM for $500 million.

In September 2009, we received $588 million from the sale of a noncontrolling interest in our midstream joint venture.

In June 2009, we received net proceeds of $54 million from the mortgage financing of our regional Barnett Shale headquarters building in Fort Worth, Texas. The interest-only loan has a five-year term at a floating rate of prime plus 275 basis points. At our option, we may prepay the loan in full without penalty beginning in year four.

In April 2009, we financed 113 real estate surface assets in the Barnett Shale area in and around Fort Worth, Texas for net proceeds of approximately $145 million and entered into a master lease agreement under which we agreed to lease the assets for 40 years for approximately $15 million to $27 million annually. This lease transaction was recorded as a financing lease.

 

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In 2011 and 2010, we received cash distributions of $85 million and $88 million, respectively, from CHKM and its predecessor. In addition, in 2011 and 2010, we received cash distributions of $28 million and $58 million, respectively, from our equity investee, FTS International, LLC and its predecessor. These cash distributions were accounted for as a return on investment and reflected as cash flows from operating activities. In 2011, we also received $206 million from FTS International, LLC at the time of its recapitalization. This cash distribution was accounted for as a return of investment and reflected as cash flows from investing activities.

Uses of Funds

Our primary use of funds is for capital expenditures related to exploration, development and acquisition of natural gas and oil properties. We refer you to the table under Investing Activities below, which sets forth the components of our natural gas and oil investing activities and our other investing activities for 2011, 2010 and 2009. We retain a significant degree of control over the timing of our capital expenditures which permits us to defer or accelerate certain capital expenditures if necessary to address any potential liquidity issues. In addition, changes in drilling and field operating costs, drilling results that alter planned development schedules, acquisitions or other factors could cause us to revise our drilling program, which is largely discretionary.

In May 2011, we completed and settled tender offers to purchase the following senior notes and contingent convertible senior notes in order to reduce the amount of our outstanding indebtedness. We funded the purchase of the notes with a portion of the net proceeds we received from the sale of our Fayetteville Shale assets.

 

     Principal
Amount
Purchased
 
     ($ in millions)  

7.625% senior notes due 2013

   $ 36   

9.5% senior notes due 2015

     160   

6.25% euro-denominated senior notes due 2017(a)

     380   

6.5% senior notes due 2017

     440   

6.875% senior notes due 2018

     126   

7.25% senior notes due 2018

     131   

6.625% senior notes due 2020

     100   
  

 

 

 

Total senior notes

     1,373   
  

 

 

 

2.75% contingent convertible senior notes due 2035

     55   

2.5% contingent convertible senior notes due 2037

     210   

2.25% contingent convertible senior notes due 2038

     266   
  

 

 

 

Total contingent convertible senior notes

     531   
  

 

 

 

Total

   $ 1,904   
  

 

 

 

 

(a)

We purchased 256 million in aggregate principal amount of our euro-denominated senior notes which had a value of $380 million based on the exchange rate of $1.4821 to 1.00. Simultaneously with our purchase of the euro-denominated senior notes, we unwound cross currency swaps for the same principal amount.

We paid $2.058 billion in cash for the tender offers described above and recorded associated losses of approximately $174 million. The losses included $154 million in cash premiums, $20 million of deferred charges, $160 million of note discounts and $2 million of interest rate hedging losses, offset by $162 million of the equity component of the contingent convertible notes.

 

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In March 2011, we repurchased $140 million in aggregate principal amount of our 2.25% Contingent Convertible Senior Notes due 2038 for approximately $128 million. Associated with these repurchases, we recognized a loss of $2 million.

In August 2010, we completed tender offers to purchase for cash $245 million of 7.00% Senior Notes due 2014, $567 million of 6.625% Senior Notes due 2016 and $582 million of 6.25% Senior Notes due 2018. In September 2010, we redeemed in whole the remaining $55 million of 7.00% Senior Notes due 2014, $33 million of 6.625% Senior Notes due 2016 and $18 million of 6.25% Senior Notes due 2018 based on the redemption provisions in the indentures. Associated with tender offers and redemptions, we recognized a loss of $40 million.

In July 2010, we redeemed in whole for a redemption price of approximately $619 million, plus accrued interest, $600 million in principal amount of our 6.375% Senior Notes due 2015. Associated with the redemption, we recognized a loss of $19 million.

In June 2010, we redeemed in whole for an aggregate redemption price of approximately $1.366 billion, plus accrued interest, approximately $364 million in principal amount of our outstanding 7.50% Senior Notes due 2013, $300 million in principal amount of our 7.50% Senior Notes due 2014 and approximately $670 million in principal amount of our 6.875% Senior Notes due 2016. Associated with the redemptions, we recognized a loss of $69 million.

We paid dividends on our common stock of $207 million, $189 million and $181 million in 2011, 2010 and 2009, respectively. The Board of Directors increased the quarterly dividend on our common stock from $0.075 to $0.0875 per share beginning with the dividend paid in July 2011. We paid dividends on our preferred stock of $172 million, $92 million and $23 million in 2011, 2010 and 2009, respectively. The increases in 2011 and 2010 were due to the issuance of 2.6 million shares of preferred stock in 2010.

Credit Risk

Derivative instruments enable us to mitigate a portion of our exposure to natural gas and oil prices and interest rate volatility expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment-grade and deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. During the more than 15 years we have engaged in hedging activities, we have experienced a counterparty default only once (Lehman Brothers in September 2008), and the total loss recorded in that instance was immaterial. On December 31, 2011, our commodity and interest rate derivative instruments were spread among 17 counterparties. Additionally, the counterparties under our multi-counterparty secured hedging facility are required to secure their natural gas and oil hedging obligations in excess of defined thresholds. We use this facility for the majority of our natural gas, oil and natural gas liquids derivatives.

Our accounts receivable are primarily from purchasers of natural gas and oil ($1.089 billion at December 31, 2011) and exploration and production companies which own interests in properties we operate ($1.171 billion at December 31, 2011). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. During 2011 and 2010, we recognized nominal amounts of bad debt expense related to potentially uncollectible receivables. During 2009, we recognized $13 million of bad debt expense related to potentially uncollectible receivables.

 

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Investing Activities

Cash used in investing activities was $5.812 billion in 2011, compared to $8.503 billion in 2010 and $5.462 billion in 2009. The majority of the decrease in investing activities in 2011 was the result of our decreased acquisition of unproved properties and additional asset monetizations, offset by an increase in drilling and completion activities. The majority of the increase in investing activities in 2010 was the result of our increased acquisition of unproved properties, primarily in liquids-rich areas, and drilling and completion activities. Investing activities in 2009 were at a reduced rate in response to a low natural gas price environment and lower demand. In each of 2011, 2010 and 2009, we also invested in drilling rigs, gathering systems, compressors, and other property and equipment to support our natural gas and oil exploration, development and production activities. The following table details our cash used in investing activities during 2011, 2010 and 2009:

 

    Years Ended December 31,  
        2011             2010             2009      
    ($ in millions)  

Natural Gas and Oil Investing Activities:

     

Drilling and completion costs on proved and unproved properties

  $ (7,257   $ (5,061   $ (3,410

Acquisition of proved properties

    (48     (243     (5

Acquisition of unproved properties

    (4,296     (6,015     (1,666

Proceeds from divestitures of proved and unproved properties

    7,651        4,292        1,926   

Geological and geophysical costs(a)

    (210     (181     (162

Interest capitalized on unproved properties

    (630     (687     (598

Deposits for acquisitions of proved and unproved properties

           (43       
 

 

 

   

 

 

   

 

 

 

Total natural gas and oil investing activities

    (4,790     (7,938     (3,915
 

 

 

   

 

 

   

 

 

 

Other Investing Activities:

     

Additions to other property and equipment

    (2,009     (1,326     (1,683

Acquisition of drilling company

    (339              

Proceeds from sales of other assets

    1,312        883        176   

Proceeds from (additions to) investments

    101        (134     (40

Other

    (87     12          
 

 

 

   

 

 

   

 

 

 

Total other investing activities

    (1,022     (565     (1,547
 

 

 

   

 

 

   

 

 

 

Total cash used in investing activities

  $ (5,812   $ (8,503   $ (5,462
 

 

 

   

 

 

   

 

 

 

 

(a)

Including related capitalized interest.

 

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Bank Credit Facilities

We utilize three revolving bank credit facilities, described below, as sources of liquidity.

 

     Corporate
Credit
Facility(a)
     Midstream
Credit
Facility(b)
    Oilfield
Services
Credit
Facility(c)
 
     ($ in millions)  

Facility structure

    
 
Senior secured
revolving
  
  
    
 
Senior secured
revolving
  
  
   
 
Senior secured
revolving
  
  

Maturity date

     December 2015         June 2016        November 2016   

Borrowing capacity

   $ 4,000       $ 600 (d)    $ 500 (e) 

Amount outstanding as of December 31, 2011

   $ 1,719       $ 1      $ 29   

Letters of credit outstanding as of December 31, 2011

   $ 38       $      $   

 

(a)

Borrower is Chesapeake Exploration, L.L.C.

 

(b)

Borrower is Chesapeake Midstream Operating, L.L.C.

 

(c)

Borrower is Chesapeake Oilfield Operating, L.L.C.

 

(d)

We estimate the capacity was limited to approximately $280 million as of December 31, 2011 by certain restrictive provisions.

 

(e)

We estimate the capacity was limited to approximately $290 million as of December 31, 2011 by certain restrictive provisions.

Our credit facilities do not contain material adverse change or adequate assurance covenants. Although the applicable interest rates under our corporate credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, our credit facilities do not contain provisions which would trigger an acceleration of amounts due under the respective facilities or a requirement to post additional collateral in the event of a downgrade of our credit ratings.

Corporate Credit Facility

Our $4.0 billion syndicated revolving bank credit facility is used for general corporate purposes. Borrowings under the facility are secured by natural gas and oil proved reserves and bear interest at our option at either (i) the greater of the reference rate of Union Bank, N.A. or the federal funds effective rate plus 0.50%, both of which are subject to a margin that varies from 0.50% to 1.25% per annum according to our senior unsecured long-term debt ratings, or (ii) the Eurodollar rate, which is based on the London Interbank Offered Rate (LIBOR), plus a margin that varies from 1.50% to 2.25% per annum according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are determined periodically. The unused portion of the facility is subject to a commitment fee of 0.50% per annum. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, make investments or loans and create liens and require us to maintain an indebtedness to total capitalization ratio and an indebtedness to EBITDA ratio, in each case as defined in the agreement. We were in compliance with all covenants under the agreement at December 31, 2011. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of

 

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$50 million or more, would constitute an event of default under our senior note indentures, which could in turn result in the acceleration of a significant portion of our senior note indebtedness. The credit facility agreement also has cross default provisions that apply to other indebtedness of Chesapeake and its restricted subsidiaries with an outstanding principal amount in excess of $125 million.

The facility is fully and unconditionally guaranteed, on a joint and several basis, by Chesapeake and certain of our wholly owned subsidiaries.

Midstream Credit Facility

Our $600 million midstream syndicated revolving bank credit facility is used to fund capital expenditures to build natural gas gathering and other systems in support of our drilling program and for general corporate purposes associated with our midstream operations. Borrowings under the midstream credit facility are secured by all of the assets other than certain joint venture equity interests, of the wholly owned subsidiaries (the restricted subsidiaries) of CMD, itself a wholly owned subsidiary of Chesapeake. Amounts outstanding bear interest at our option at either (i) the greater of the reference rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month LIBOR plus 1.00%, all of which are subject to a margin that varies from 1.00% to 1.75% or (ii) the Eurodollar rate, which is based on LIBOR plus a margin that varies from 2.00% to 2.75% per annum. The unused portion of the facility is subject to a commitment fee that varies from 0.375% to 0.50% per annum. Both margins and commitment fees are determined according to the most recent leverage ratio described below. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The midstream credit facility agreement contains various covenants and restrictive provisions which limit the ability of CMD and its restricted subsidiaries to incur additional indebtedness, make investments or loans and create liens. The agreement requires maintenance of a leverage ratio based on the ratio of indebtedness to EBITDA and an interest coverage ratio based on the ratio of EBITDA to interest expense, in each case as defined in the agreement. The leverage ratio increases during any three-quarter period, beginning in the quarter in which CMD makes a material disposition of assets to our midstream master limited partnership affiliate, CHKM. In December 2011, the leverage ratio increased for a three-fiscal-quarter period beginning October 1, 2011 due to the sale of CMD’s wholly owned subsidiary, AMS, as it was classified as a material disposition of assets. We were in compliance with all covenants under the agreement at December 31, 2011. If CMD or its restricted subsidiaries should fail to perform their obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. The midstream credit facility agreement also has cross default provisions that apply to other indebtedness CMD and its restricted subsidiaries may have from time to time with an outstanding principal amount in excess of $15 million.

Oilfield Services Credit Facility

In November 2011, we closed on a new syndicated revolving bank credit facility for our oilfield services operations, which have recently been segregated under the wholly owned subsidiary, COS, and its wholly owned subsidiary, COO. The facility matures in November 2016, has initial commitments of $500 million and may be expanded to $900 million at COO’s option, subject to additional bank participation. The facility is used to fund capital expenditures and for general corporate purposes associated with our oilfield services operations. Borrowings under the credit facility are secured by all of the equity interests and assets of COO and its wholly owned subsidiaries (the restricted subsidiaries), and bear interest at our option at either (i) the greater of the reference rate of Bank of America, N.A., the federal funds effective rate plus 0.50%, and one-month LIBOR plus 1.00%, all of which are subject to a margin that varies from 1.00% to 1.75% per annum or (ii) the Eurodollar rate, which is based on LIBOR plus a margin that varies from 2.00% to 2.75% per annum. The unused

 

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portion of the credit facility is subject to a commitment fee that varies from 0.375% to 0.50% per annum. Both margins and commitment fees are determined according to the most recent leverage ratio described below. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The oilfield services credit facility agreement contains various covenants and restrictive provisions which limit the ability of COO and its restricted subsidiaries to incur additional indebtedness, make investments or loans and create liens. The agreement requires maintenance of a leverage ratio based on the ratio of lease adjusted indebtedness to EBITDAR, a senior secured leverage ratio based on the ratio of secured indebtedness to EBITDA and a fixed charge coverage ratio based on the ratio of lease adjusted interest expense to EBITDAR, in each case as defined in the agreement. We were in compliance with all covenants under the agreement at December 31, 2011. If COO or its restricted subsidiaries should fail to perform their obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. The oilfield services credit facility agreement also has cross default provisions that apply to other indebtedness COO and its restricted subsidiaries may have from time to time with an outstanding principal amount in excess of $15 million.

Hedging Facility

We have a multi-counterparty secured hedging facility with 18 counterparties that have committed to provide approximately 6.5 tcfe of hedging capacity for commodity price derivatives and 6.5 tcfe for basis derivatives with an aggregate mark-to-market capacity of $17.5 billion under the terms of the facility. As of December 31, 2011, we had hedged under the facility 2.1 tcfe of our future production with price derivatives and 0.1 tcfe with basis derivatives. The multi-counterparty facility allows us to enter into cash-settled natural gas, oil and natural gas liquids price and basis derivative instruments with the counterparties. Our obligations under the multi-counterparty facility are secured by proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times, and guarantees by certain subsidiaries that also guarantee our corporate revolving bank credit facility and indentures. The counterparties’ obligations under the facility must be secured by cash or short-term U.S. Treasury instruments to the extent that any mark-to-market amounts they owe to Chesapeake exceed defined thresholds. The maximum volume-based trading capacity under the facility is governed by the expected production of the pledged reserve collateral, and volume-based trading limits are applied separately to price and basis derivative instruments. In addition, there are volume-based sub-limits for natural gas, oil and natural gas liquids derivative instruments. Chesapeake has significant flexibility with regard to releases and/or substitutions of pledged reserves, provided that certain collateral coverage and other requirements are met. The facility does not have a maturity date. Counterparties to the agreement have the right to cease entering into derivative instruments with the Company on a prospective basis as long as obligations associated with any existing transactions in the facility continue to be satisfied in accordance with the terms of the agreement.

 

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Senior Note Obligations

In addition to outstanding borrowings under our revolving bank credit facilities discussed above, as of December 31, 2011, our long-term debt consisted of the following ($ in millions):

 

7.625% senior notes due 2013

   $         464   

9.5% senior notes due 2015

     1,265   

6.25% euro-denominated senior notes due 2017(a)

     446   

6.5% senior notes due 2017

     660   

6.875% senior notes due 2018

     474   

7.25% senior notes due 2018

     669   

6.625% senior notes due 2019(b)

     650   

6.625% senior notes due 2020

     1,300   

6.875% senior notes due 2020

     500   

6.125% senior notes due 2021

     1,000   

2.75% contingent convertible senior notes due 2035(c )

     396   

2.5% contingent convertible senior notes due 2037(c )

     1,168   

2.25% contingent convertible senior notes due 2038(c )

     347   

Discount on senior notes(d)

     (490

Interest rate derivatives(e)

     28   
  

 

 

 
   $ 8,877   
  

 

 

 

 

(a)

The principal amount shown is based on the dollar/euro exchange rate of $1.2973 to 1.00 as of December 31, 2011. See Note 9 of our consolidated financial statements included in Item 8 of this report for information on our related foreign currency derivatives.

 

(b)

Issuers are COO and Chesapeake Oilfield Finance, Inc., a wholly owned subsidiary of COO formed solely to facilitate the offering of the 6.625% Senior Notes due 2019. It is nominally capitalized and has no operations or revenues. Chesapeake Energy Corporation is the issuer of all other senior notes and the contingent convertible senior notes.

 

(c)

The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date. The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash and, if applicable, shares of our common stock using a net share settlement process. One such triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarter by quarter. In the fourth quarter of 2011, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes during the specified period and, as a result, the holders do not have the option to convert their notes into cash and common stock in the first quarter of 2012 under this provision. The notes are also convertible, at the holder’s option, during specified five-day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note’s conversion value in excess of such principal amount. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years, under certain conditions. We may redeem the convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of the notes, payable in cash. The optional repurchase dates, the common stock price conversion threshold amounts and the ending date of the first six-month period contingent interest may be payable for the contingent convertible senior notes are as follows:

 

Contingent

Convertible

Senior Notes

 

Repurchase Dates

  Common Stock
Price Conversion
Thresholds
    Contingent Interest
First Payable

(if applicable)

2.75% due 2035

 

November 15, 2015, 2020, 2025, 2030

  $ 48.51     

May 14, 2016

2.5% due 2037

 

May 15, 2017, 2022, 2027, 2032

  $ 64.16     

November 14, 2017

2.25% due 2038

 

December 15, 2018, 2023, 2028, 2033

  $ 107.27     

June 14, 2019

 

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(d)

Included in this discount is $444 million associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method.

 

(e)

See Note 9 of our consolidated financial statements included in Item 8 of this report for discussion related to these instruments.

Chesapeake Senior Notes and Contingent Convertible Notes

The Chesapeake senior notes and the contingent convertible senior notes, as defined in note (b) to the table above, are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Chesapeake is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Chesapeake’s obligations under the senior notes and the contingent convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our wholly owned subsidiaries. CMD and its subsidiaries, COS and its subsidiaries, CHK Utica, Chesapeake Granite Wash Trust and certain de minimis subsidiaries are not guarantors. See Note 18 of the notes to our consolidated financial statements in Item 8 of this report for condensed consolidating financial information regarding our guarantor and non-guarantor subsidiaries. We may redeem the senior notes, other than the contingent convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale/leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the contingent convertible senior notes do not have any financial or restricted payment covenants.

We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense at the interest rate of similar nonconvertible debt at the time of issuance. These rates for our 2.75% Contingent Convertible Senior Notes due 2035, our 2.5% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038 are 6.86%, 8.0% and 8.0%, respectively.

COO Senior Notes

In October 2011, our wholly owned subsidiary, COO, issued $650 million principal amount of 6.625% Senior Notes due 2019 in a private placement. COO used the net proceeds of approximately $637 million from the placement to make a cash distribution to its direct parent, Chesapeake Oilfield Services, L.L.C., to enable it to reduce indebtedness under an intercompany note with Chesapeake. Chesapeake then used the cash distribution to reduce indebtedness under its corporate revolving bank credit facility.

The COO senior notes are the unsecured senior obligations of COO and rank equally in right of payment with all of COO’s other existing and future senior unsecured indebtedness and rank senior in right of payment to all of its future subordinated indebtedness. The COO senior notes are jointly and severally, fully and unconditionally guaranteed by all of COO’s wholly owned subsidiaries, other than de minimus subsidiaries. The notes may be redeemed at any time at specified make-whole or redemption prices and, prior to November 15, 2014, up to 35% of the aggregate principal amount may be redeemed in connection with certain equity offerings. Holders of the COO notes have the right to require COO to repurchase their notes upon a change of control on the terms set forth in the indenture, and COO must offer to repurchase the notes upon certain asset sales. The COO senior notes are subject to covenants that may, among other things, limit the ability of COO and its subsidiaries to make restricted payments, incur indebtedness, issue preferred stock, create liens, and consolidate, merge or transfer assets.

 

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Conversions and Exchanges of Contingent Convertible Senior Notes and Preferred Stock

In 2010 and 2009, holders of certain of our contingent convertible senior notes exchanged their notes for shares of common stock in privately negotiated exchanges as summarized below.

 

Year

  

Contingent Convertible

Senior Notes

   Principal Amount      Number of
Common Shares
 
          ($ in millions)      (in thousands)  

2010

   2.25% due 2038    $ 11         299   
     

 

 

    

 

 

 

2009

   2.25% due 2038    $ 364         10,210   
     

 

 

    

 

 

 

In 2011, 2010 and 2009, shares of our cumulative convertible preferred stock were converted into shares of common stock as summarized below.

 

Year of
Conversion

  

Cumulative Convertible

Preferred Stock

   Number of
Preferred
Shares
     Number of
Common
Shares
 
          (in thousands)  

2011

   5.75%      3         111   
        

 

 

 

2010

   5.0% (series 2005)      5         21   
        

 

 

 

2009

   6.25%      144             1,239   
   4.125%      3         183   
        

 

 

 
           1,422   
        

 

 

 

Contractual Obligations and Off-balance Sheet Arrangements

From time to time, we enter into arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2011, these arrangements and transactions included (i) operating lease agreements, (ii) VPP obligations (to physically deliver volumes and pay related lease operating expenses in the future), (iii) open purchase commitments, (iv) open delivery commitments, (v) open drilling commitments, (vi) undrawn letters of credit and (vii) variable interests held in VIEs. Other than described above, we have no off-balance sheet arrangements or transactions that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources.

 

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The table below summarizes our contractual cash obligations for both recorded obligations and certain off-balance sheet arrangements and commitments as of December 31, 2011.

 

     Payments Due By Period  
         Total          Less Than
1 Year
     1-3
    Years    
     3-5
    Years    
     More Than
5 Years
 
     ($ in millions)  

Long-term debt:

              

Principal

   $ 11,087       $       $ 464       $ 3,014       $ 7,609   

Interest

     4,529         580         1,110         867         1,972   

Financing lease obligations and other(a)

     869         18         91         33         727   

Operating lease obligations(b)

     998         200         444         273         81   

Asset retirement obligations(c )

     323         5         47         12         259   

Purchase obligations(d)

     14,441         1,486         2,605         2,686         7,664   

Unrecognized tax benefits(e)

     246                         246           

Standby letters of credit

     38         38                           

Other

     69         13         27         7         22   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual cash obligations

   $ 32,600       $ 2,340       $ 4,788       $ 7,138       $ 18,334   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a)

See Note 1 of the notes to our consolidated financial statements in Item 8 of this report for a description of our other long-term liabilities.

 

(b)

See Note 4 of the notes to our consolidated financial statements in Item 8 of this report for a description of our operating lease obligations.

 

(c)

Asset retirement obligations represent estimated discounted costs for future dismantlement and abandonment costs. These obligations are recorded as liabilities on our December 31, 2011 balance sheet.

 

(d)

See Note 4 of the notes to our consolidated financial statements in Item 8 of this report for a description of transportation and drilling contract commitments.

 

(e)

See Note 5 of the notes to our consolidated financial statements in Item 8 of this report for a description of unrecognized tax benefits.

In addition to the obligations in the table above, we enter into various commitments through the normal course of business that could potentially result in a future cash obligation that we are unable to quantify. See Note 4 of the notes to our consolidated financial statements in Item 8 of this report for further discussion. Also, see Note 13 of the notes to our consolidated financial statements in Item 8 of this report for further discussion of VIEs.

Hedging Activities

Natural Gas and Oil Derivatives

Our results of operations and cash flows are impacted by changes in market prices for natural gas and oil. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Executive management is involved in all risk management activities and the Board of Directors reviews the Company’s hedging program at its quarterly board meetings. We believe we have sufficient internal controls to prevent unauthorized hedging. As of December 31, 2011, our natural gas and oil derivative instruments were comprised of swaps, call options, swaptions, knockout swaps and basis protection swaps. Item 7A. Quantitative and Qualitative Disclosures About Market Risk contains a description of each of these instruments and realized and unrealized gains and losses on natural gas and oil derivatives during 2011, 2010 and 2009. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving our risk management objectives.

 

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Hedging allows us to predict with greater certainty the effective prices we will receive for our hedged production. We closely monitor the fair value of our derivative contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or loss. Commodity markets are volatile and Chesapeake’s hedging activities are dynamic.

Mark-to-market positions under natural gas and oil derivative contracts fluctuate with commodity prices. As described above under Hedging Facility, our secured multi-counterparty hedging facility allows us to minimize the potential liquidity impact of significant mark-to-market fluctuations in the value of our natural gas and oil derivatives by pledging natural gas and oil proved reserves.

The estimated fair values of our natural gas and oil derivative contracts as of December 31, 2011 and 2010 are provided below. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk of this report for additional information concerning the fair value of our natural gas and oil derivative instruments.

 

     December 31,  
         2011             2010      
     ($ in millions)  

Derivative assets (liabilities):

    

Fixed-price natural gas swaps

   $      $ 1,307   

Natural gas call options

     (284     (701

Natural gas put options

            (59

Natural gas basis protection swaps

     (42     (55

Fixed-price oil swaps

     15        (31

Oil call options

     (1,282     (1,129

Oil swaptions

     (53       

Fixed-price oil knockout swaps

     7        19   
  

 

 

   

 

 

 

Estimated fair value

   $ (1,639   $ (649
  

 

 

   

 

 

 

Changes in the fair value of natural gas and oil derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to the hedged commodities, and locked-in gains and losses of settled qualifying derivative contracts are recorded in accumulated other comprehensive income and are transferred to earnings in the month of related production. These unrealized gains (losses), net of related tax effects, totaled ($162) million, ($156) million and $94 million as of December 31, 2011, 2010 and 2009, respectively. Based upon the market prices at December 31, 2011, we expect to transfer to earnings approximately $17 million of net gain included in accumulated other comprehensive income during the next 12 months. A detailed explanation of accounting for natural gas and oil derivatives appears under Application of Critical Accounting Policies – Hedging elsewhere in this Item 7.

Interest Rate Derivatives

To mitigate our exposure to volatility in interest rates related to our senior notes and credit facilities, we enter into interest rate derivatives.

For interest rate derivative contracts designated as fair value hedges, changes in fair values of the derivatives are recorded on the consolidated balance sheets as assets or (liabilities), with corresponding offsetting adjustments to the debt’s carrying value. Changes in the fair value of non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in mark-to-market values) are reported currently in the consolidated statements of operations as interest expense and characterized as unrealized gains (losses).

 

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Gains or losses from interest rate derivative contracts are reflected as adjustments to interest expense on the consolidated statements of operations. The components of interest expense for the years ended December 31, 2011, 2010 and 2009 are presented in Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and a detailed explanation of accounting for interest rate derivatives appears under Application of Critical Accounting Policies – Hedging elsewhere in this Item 7.

Foreign Currency Derivatives

On December 6, 2006, we issued 600 million of 6.25% Euro-denominated Senior Notes due 2017. Concurrent with the issuance of the euro-denominated senior notes, we entered into cross currency swaps to mitigate our exposure to fluctuations in the euro relative to the dollar over the term of the notes. In May 2011, we purchased and subsequently retired 256 million in aggregate principal amount of these senior notes following a tender offer, and we simultaneously unwound the cross currency swaps for the same principal amount. A detailed explanation of accounting for foreign currency derivatives appears under Application of Critical Accounting Policies – Hedging elsewhere in this Item 7.

Results of Operations

General. For the year ended December 31, 2011, Chesapeake had net income of $1.742 billion, or $2.32 per diluted common share, on total revenues of $11.635 billion. This compares to net income of $1.774 billion, or $2.51 per diluted common share, on total revenues of $9.366 billion during the year ended December 31, 2010, and a net loss of $5.830 billion, or $9.57 per diluted common share, on total revenues of $7.702 billion during the year ended December 31, 2009.

Natural Gas and Oil Sales. During 2011, natural gas and oil sales were $6.024 billion compared to $5.647 billion in 2010 and $5.049 billion in 2009. In 2011, Chesapeake produced and sold 1.194 tcfe of natural gas and oil at a weighted average price of $5.70 per mcfe, compared to 1.035 tcfe in 2010 at a weighted average price of $6.09 per mcfe, and 905.5 bcfe in 2009 at a weighted average price of $6.22 per mcfe (weighted average prices for all years discussed exclude the effect of unrealized losses on derivatives of $789 million, $657 million and $588 million in 2011, 2010 and 2009, respectively). The decrease in prices in 2011 resulted in a decrease in revenue of $461 million and increased production resulted in a $968 million increase, for a total increase in revenues of $507 million (excluding unrealized gains or losses on natural gas and oil derivatives). The increase in production from period to period was primarily generated from the drillbit.

For 2011, we realized an average price per mcf of natural gas of $4.77, compared to $5.57 in 2010 and $5.93 in 2009 (weighted average prices for all years discussed exclude the effect of unrealized gains or losses on derivatives). Included in the 2011 and 2010 realized price of natural gas are gains related to swaps that had an above-market fixed price on the origination date. We obtained these above-market swaps by selling out-year call options on a portion of our projected natural gas and oil production. See Item 7A for a complete listing of all of our derivative instruments. Oil prices realized per barrel (excluding unrealized gains or losses on derivatives) were $63.90, $62.71 and $58.38 in 2011, 2010 and 2009, respectively. Realized gains or losses from our natural gas and oil derivatives resulted in a net increase in natural gas and oil revenues of $1.554 billion, or $1.30 per mcfe, in 2011, a net increase of $2.056 billion, or $1.99 per mcfe, in 2010 and a net increase of $2.346 billion, or $2.59 per mcfe, in 2009.

A change in natural gas and oil prices has a significant impact on our natural gas and oil revenues and cash flows. Assuming 2011 production levels, an increase or decrease of $0.10 per mcf of natural gas sold would result in an increase or decrease in 2011 revenues and cash flows of approximately $100 million and $97 million, respectively, and an increase or decrease of $1.00 per

 

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barrel of oil sold would result in an increase or decrease in 2011 revenues and cash flows of approximately $32 million and $30 million, respectively, without considering the effect of hedging activities.

The following tables show our production and prices by operating division for 2011, 2010 and 2009:

 

     2011  
     Natural Gas      Oil(a)      Total  
     (bcf)      ($/mcf)(b)      (mmbbl)      ($/bbl)(b)      (bcfe)      %     ($/mcfe)(b)  

Southern(c)

     554.7         2.83         1.1         39.50         561.8         47     2.89   

Northern

     258.2         3.55         20.9         64.61         383.0         32        5.90   

Eastern

     135.8         3.27         1.5         59.79         144.8         12        3.69   

Western

     55.4         3.58         8.2         78.28         104.6         9        8.04   
  

 

 

       

 

 

       

 

 

    

 

 

   

Total(d)

     1,004.1         3.12         31.7         67.11         1,194.2         100     4.40   
  

 

 

       

 

 

       

 

 

    

 

 

   
     2010  
     Natural Gas      Oil(a)      Total  
     (bcf)      ($/mcf)(b)      (mmbbl)      ($/bbl)(b)      (bcfe)      %     ($/mcfe)(b)  

Southern(c)

     418.7         2.98         0.8         29.91         423.4         42     3.01   

Northern

     368.8         3.73         13.8         56.57         451.3         43        4.78   

Eastern

     74.1         3.68         0.4         51.67         76.8         7        3.85   

Western

     63.3         4.28         3.4         74.42         83.7         8        6.25   
  

 

 

       

 

 

       

 

 

    

 

 

   

Total(d)

     924.9         3.43         18.4         58.67         1,035.2         100     4.10   
  

 

 

       

 

 

       

 

 

    

 

 

   
     2009  
     Natural Gas      Oil(a)      Total  
     (bcf)      ($/mcf)(b)      (mmbbl)      ($/bbl)(b)      (bcfe)      %     ($/mcfe)(b)  

Southern(c)

     346.0         2.46         0.3         52.65         347.7         39     2.50   

Northern

     349.3         3.60         7.8         55.24         395.6         44        4.25   

Eastern

     43.2         3.82         0.2         53.12         44.8         4        3.98   

Western

     96.3         3.77         3.5         56.82         117.4         13        4.79   
  

 

 

       

 

 

       

 

 

    

 

 

   

Total(d)

     834.8         3.16         11.8         55.60         905.5         100     3.63   
  

 

 

       

 

 

       

 

 

    

 

 

   

 

(a)

Includes NGLs.

 

(b)

The average sales price excludes gains (losses) on derivatives.

 

(c)

Our Southern division primarily includes the Haynesville/Bossier Shale and the Barnett Shale which hold approximately 22% and 20% of our estimated proved reserves by volume as of December 31, 2011. Production for the Haynesville/Bossier Shale for the years ended 2011, 2010 and 2009 was 408.7 bcfe, 239.3 bcfe and 87.2 bcfe, respectively. Production for the Barnett Shale for the years ended 2011, 2010 and 2009 was 143.7 bcfe, 176.3 bcfe and 238.0 bcfe, respectively.

 

    

Our Barnett Shale production is concentrated in urban areas where the cost to develop the necessary infrastructure to gather and deliver the natural gas to intrastate pipelines significantly exceeds the cost of similar infrastructure in non-urban areas. Additionally, the rapid development of the Barnett Shale required the construction of new pipelines to provide an adequate market for these new gas reserves. In order to support the timely construction of these new pipelines, we

 

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entered into firm transportation contracts that obligate the Company to pay demand fees even if we do not deliver specified volumes of natural gas into certain gathering systems and intrastate pipelines. The demand fees associated with unused capacity and the other gathering and transportation fees described above have resulted in lower natural gas price realizations in the Barnett Shale.

 

(d)

2011 period production reflects the sale of all of our Fayetteville Shale assets, which closed in March 2011 and various other asset sales, including VPP #6, VPP #7, VPP #8 and VPP #9, which closed in February 2010, June 2010, September 2010 and May 2011, respectively. See Note 11 of the notes to our consolidated financial statements included in Item 8 of this report for information on divestitures.

Our average daily production of 3.272 bcfe for 2011 consisted of 2.751 bcf of natural gas (84% on a natural gas equivalent basis) and 86,784 bbls of liquids (16% on a natural gas equivalent basis). Our year-over-year growth rate of natural gas production was 9% and our year-over-year growth rate of liquids production was 72%. Our percentage of revenue from liquids in 2011 was 40% of unhedged natural gas and oil revenue compared to 25% in 2010 and 20% in 2009.