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, 2008

 

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

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 $.01    New York Stock Exchange
7.5% Senior Notes due 2013    New York Stock Exchange
7.625% Senior Notes due 2013    New York Stock Exchange
7.0% Senior Notes due 2014    New York Stock Exchange
7.5% Senior Notes due 2014    New York Stock Exchange
6.375% Senior Notes due 2015    New York Stock Exchange
9.5% Senior Notes due 2015    New York Stock Exchange
6.625% Senior Notes due 2016    New York Stock Exchange
6.875% Senior Notes due 2016    New York Stock Exchange
6.5% Senior Notes due 2017    New York Stock Exchange
6.25% Senior Notes due 2018    New York Stock Exchange
7.25% Senior Notes due 2018    New York Stock Exchange
6.875% Senior Notes due 2020    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
6.25% Mandatory 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

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

 

Large Accelerated Filer  x   Accelerated Filer  ¨   Non-accelerated Filer  ¨   Smaller Reporting Company  ¨

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

The aggregate market value of our common stock held by non-affiliates on June 30, 2008 was approximately $29.5 billion. At February 26, 2009, there were 624,477,656 shares of our $0.01 par value common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the 2009 Annual Meeting of Shareholders are incorporated by reference in Part III.

 

 

 


Table of Contents

CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES

2008 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

 

   PART I   
          Page

ITEM 1.

  

Business

   1

ITEM 1A.

  

Risk Factors

   22

ITEM 1B.

  

Unresolved Staff Comments

   29

ITEM 2.

  

Properties

   29

ITEM 3.

  

Legal Proceedings

   29

ITEM 4.

  

Submission of Matters to a Vote of Security Holders

   30
PART II

ITEM 5.

  

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

   31

ITEM 6.

  

Selected Financial Data

   33

ITEM 7.

  

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

   34

ITEM 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

   58

ITEM 8.

  

Financial Statements and Supplementary Data

   65

ITEM 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   129

ITEM 9A.

  

Controls and Procedures

   129

ITEM 9B.

  

Other Information

   129
PART III

ITEM 10.

  

Directors, Executive Officers and Corporate Governance

   130

ITEM 11.

  

Executive Compensation

   130

ITEM 12.

  

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

   130

ITEM 13.

  

Certain Relationships and Related Transactions and Director Independence

   130

ITEM 14.

  

Principal Accountant Fees and Services

   130
PART IV

ITEM 15.

  

Exhibits and Financial Statement Schedules

   131


Table of Contents

PART I

 

ITEM 1. Business

General

We are the largest independent producer of natural gas in the United States. We own interests in approximately 41,200 producing natural gas and oil wells that are currently producing approximately 2.3 billion cubic feet equivalent (bcfe) per day, 92% of which is natural gas. Our strategy is focused on discovering, developing and acquiring conventional and unconventional natural gas reserves onshore in the U.S., primarily in the “Big 4” natural gas shale plays: the Barnett Shale in the Forth Worth Basin of north-central Texas, the Haynesville Shale in the Ark-La-Tex area of northwestern Louisiana and East Texas, the Fayetteville Shale in the Arkoma Basin of central Arkansas and the Marcellus Shale in the northern Appalachian Basin of West Virginia, Pennsylvania and New York. We also have substantial operations in various other plays, both conventional and unconventional, in the Mid-Continent, Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast and Ark-La-Tex regions of the U.S.

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

As of December 31, 2008, we had 12.051 trillion cubic feet equivalent, or tcfe, of proved reserves, of which 94% were natural gas and all of which were onshore in the U.S. During 2008, we produced an average of 2.303 bcfe per day, an 18% increase over the 1.957 bcfe per day produced in 2007. We replaced our 843 bcfe of production with an internally estimated 2.015 tcfe of new proved reserves for a reserve replacement rate of 239%. Reserve replacement through the drillbit was 2.545 tcfe, or 302% of production including 1.248 tcfe of positive performance revisions and 298 bcfe of negative revisions resulting from natural gas and oil price decreases between December 31, 2007 and December 31, 2008. Reserve replacement through the acquisition of proved reserves was 172 bcfe. During 2008, we divested 702 bcfe of estimated proved reserves. In total, our proved reserves grew by 11% during 2008, from 10.9 tcfe to 12.1 tcfe. Of our 12.1 tcfe of proved reserves, 67% were proved developed reserves.

During 2008, Chesapeake continued the industry’s most active drilling program and drilled 1,819 gross (1,491 net) operated wells and participated in another 1,857 gross (242 net) wells operated by other companies. The company’s drilling success rate was 99% for company-operated wells and 98% for non-operated wells. Also during 2008, we invested $5.043 billion in operated wells (using an average of 145 operated rigs) and $754 million in non-operated wells (using an average of 110 non-operated rigs) for total drilling, completing and equipping costs of $5.797 billion.

During the second half of 2008, we entered into joint venture arrangements that monetized a portion of our investment in three of the Big 4 Shale plays and provide drilling cost carries for our retained interest. In the Haynesville Shale, we entered into a joint venture with Plains Exploration & Production Company in July 2008 in which we sold Plains a 20% interest in our Haynesville properties and received an upfront cash payment of $1.65 billion and drilling cost carries of up to $1.65 billion. In the Fayetteville Shale, we entered into a joint venture with BP America Production Company in September 2008 in which we sold BP a 25% interest in our Fayetteville properties and received an upfront cash payment of $1.1 billion and drilling cost carries of $800 million. Most recently, we entered into a joint venture with StatoilHydro ASA in November 2008 in which we sold a 32.5% interest in our Marcellus properties and received an upfront cash payment of $1.25 billion and drilling cost carries of $2.125 billion. Collectively in these three joint ventures, we received upfront cash payments of $4.0 billion and future drilling cost carries of up to $4.6 billion for total consideration of up to $8.6 billion against a cost basis of approximately $1.2 billion in the property interests we sold. Moreover, Chesapeake

 

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retained an 80% interest in the Haynesville Shale properties, a 75% interest in the Fayetteville Shale properties and a 67.5% interest in the Marcellus Shale properties.

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. References to “us”, “we” and “our” in this report refer to Chesapeake Energy Corporation together with its subsidiaries.

Business Strategy

Since our inception in 1989, Chesapeake’s goal has been to create value for investors by building one of the largest onshore natural gas resource bases in the United States. For the past eleven years, our strategy to accomplish this goal has been to focus on developing unconventional plays onshore in the U.S., where we believe we can generate the most attractive risk adjusted returns. In building our industry-leading natural gas resource base during the period from 1998 to 2008, we integrated an aggressive and technologically-advanced drilling program with an active property consolidation program focused on small to medium-sized corporate and property acquisitions. During the past two years, we have shifted our strategy from drilling inventory capture to drilling inventory conversion. In doing so, we have de-emphasized acquisitions of proved properties while further emphasizing our industry-leading drilling program and converting our substantial backlog of drilling opportunities into proved developed producing reserves through the drillbit. 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 reserves organically through the drillbit. We are currently utilizing 112 operated drilling rigs and 75 non-operated drilling rigs to conduct the most active drilling program in the U.S. We are active in most of the unconventional plays in the U.S., where we drill more horizontal wells than any other company in the industry. For several years, we have been actively investing in leasehold, 3-D seismic information and human capital 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 the past 19 consecutive years. We believe the key elements of the success and scale of our drilling programs have been our recognition earlier than most of our competitors that (i) natural gas and oil prices, while remaining cyclical and volatile, were likely to move structurally higher for an extended period, (ii) new horizontal drilling and completion techniques would enable development of previously uneconomic natural gas reservoirs and (iii) various shale formations could be recognized and developed as potentially prolific natural gas reservoirs rather than just as source rocks for conventional natural gas reservoirs. In response to our early recognition of these trends, we have proactively hired thousands of new employees and have built the nation’s largest onshore leasehold and 3-D seismic inventories. These stand as 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. Anticipating an increase in natural gas and oil prices and recognizing that better horizontal drilling and completion technologies when applied to various new shale plays would likely create a unique opportunity to capture decades worth of drilling opportunities, we embarked on a very aggressive lease acquisition program which we have referred to as the “land grab”. We believed that the winner of the “land grab” would enjoy a distinctive competitive advantage for decades to come as other companies would be locked out of the best new shale plays in the U.S. We believe that we have executed our “land grab” strategy with particular distinction. We now own approximately 15 million net acres of leasehold in the U.S. and have identified more than 36,000 drilling opportunities on this leasehold. We believe this deep backlog of drilling, more than ten years worth at current drilling levels, provides unusual confidence and transparency into our future growth capabilities.

 

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Develop Proprietary Technological Advantages.    In addition to our industry-leading leasehold position, we have developed a number of proprietary technological advantages. First, we have acquired what we believe is the nation’s largest inventory of three-dimensional (3-D) seismic information. Possessing this 3-D seismic data enables us to image reservoirs of natural gas that might otherwise remain undiscovered and to drill our horizontal wells more accurately inside the targeted shale 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 insight into new plays and competitor activity. As a result of our initiatives, we now produce approximately 4% of the nation’s natural gas, drill 13% 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 shale wells on a proprietary basis and then identify new plays and leasing opportunities ahead of our competition to improve existing plays. It also allows us to design fracture stimulation procedures that might work most productively in the shale formations that we aggressively drill. We believe the RTC provides a very substantial competitive advantage in developing new shale plays and improving existing shale plays.

Build Regional Scale.    We believe one of the keys to success in the natural gas exploration industry is to build significant operating scale in a limited number of operating 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 costs, 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 the Big 4 shale plays, we will continue to achieve even greater regional scale in north Texas for the Barnett, northwestern Louisiana and East Texas for the Haynesville, central Arkansas for the Fayetteville and northeastern and southwestern Pennsylvania and northern West Virginia for the Marcellus.

Focus on Low Costs.    By proactively hedging the prices we receive for a majority of our natural gas and oil production and by minimizing lease operating costs and general and administrative expenses through focused activities and increased 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, extensive and competitive services and natural gas processing and transportation infrastructures that exist in our key operating areas. In addition, to control costs and service provider quality, we have made significant investments in our drilling rig and trucking service operations and in our midstream gathering and compression operations. As of December 31, 2008, we operated approximately 23,800 of our 41,200 wells, which delivered approximately 86% of our daily production volume. This large percentage of operated properties provides us with a high degree of operating flexibility and cost control.

Mitigate Natural Gas and Oil Price Risk.    We have used and intend to continue using hedging programs to mitigate the risks inherent in developing and producing natural gas and oil reserves, commodities that are frequently characterized by significant price volatility. We believe this price volatility is likely to continue in the years ahead and that we can 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. As of February 17, 2009, we have natural gas and oil swaps and collars in place covering 78% and 48% of our expected production in 2009 and 2010, at average prices of $7.71 per mcfe and $9.02 per mcfe, respectively, thereby providing price certainty for a substantial portion of our future cash flow.

Form Unique Joint Venture Arrangements.    In the second half of 2008, the company entered into three joint venture arrangements covering three of the company’s Big 4 shale plays. In the joint ventures, the company has collaborated with other leading energy companies to accelerate the development of the company’s properties in the Haynesville Shale, the Fayetteville Shale and the Marcellus Shale. In total, we sold leasehold and producing property assets in which we had a cost basis of approximately $1.2 billion to these three joint venture

 

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partners for total cash consideration of $4.0 billion and up to $4.6 billion of future drilling cost carries while we retained a majority interest in each joint venture. The drilling cost carries of up to approximately $4.2 billion that remain unused as of December 31, 2008 will be extremely valuable in the years ahead by enabling the company to develop reserves in these joint venture shale plays at greatly reduced costs. We are also considering opportunities for other joint venture transactions to develop our properties.

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 extremes of natural gas and oil prices to create the largest independent producer of natural gas in the U.S. with approximately 7,600 employees currently. The company takes pride in its innovative and aggressive implementation of its business strategy and strives to be as entrepreneurial today as it has been in its past. 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.

Improve our Balance Sheet.    We have made significant progress in improving our balance sheet over the past ten years. From December 31, 1998 through December 31, 2008, we increased our stockholders’ equity by $16.5 billion through a combination of earnings and common and preferred equity issuances. As of December 31, 2008, our debt as a percentage of total capitalization (total capitalization is the sum of debt less cash on hand and stockholders’ equity) was 43%, compared to 131% as of December 31, 1998 and 47% as of December 31, 2007.

Outlook

We believe that demand for natural gas will increase in the U.S. and around the world because of its favorable environmental characteristics and relative abundance. This outlook is gathering more national attention when compared to oil, which is likely to return to being in increasingly short supply once the current worldwide recession is over, and to coal, which has many unfavorable environmental characteristics. Chesapeake’s strategy for 2009 is to continue developing our natural gas assets, especially in our Big 4 Shale plays, in which we anticipate investing approximately 70% of our drilling capital in 2009, through exploratory and developmental drilling and by selectively acquiring strategic properties in the Mid-Continent and in our other operating areas. We project that our 2009 production will be between 875 bcfe and 885 bcfe, a 4% to 5% increase over 2008 production. We have budgeted $3.3 billion to $3.6 billion for drilling, acreage acquisition, seismic and related capitalized internal costs, which is expected to be funded with operating cash flow based on our current assumptions, our 2009-2010 financial plan and borrowings under our revolving bank credit facility. Our budget is frequently adjusted based on changes in natural gas and oil prices, drilling results, drilling costs and other factors.

Operating Areas

Chesapeake focuses its natural gas exploration, development and acquisition efforts in the six operating areas described below.

Mid-Continent (including the Fayetteville Shale).    Chesapeake’s Mid-Continent proved reserves of 4.456 tcfe represented 37% of our total proved reserves as of December 31, 2008, and this area produced 413 bcfe, or 49%, of our 2008 production. During 2008, we invested approximately $2.3 billion to drill 2,096 (714 net) wells in the Mid-Continent. For 2009, we anticipate spending approximately $610 million, or 21% of our total budget for exploration and development activities, net of carries, in the Mid-Continent region. BP, our Fayetteville Shale joint venture partner, has committed to pay up to $800 million of our drilling, completing and equipping costs in the play. Of the total $800 million drilling cost carry, $256 million was applied in 2008, and we expect the remaining $544 million will be applied in 2009.

Barnett Shale.    Chesapeake’s Barnett Shale proved reserves represented 2.935 tcfe, or 24%, of our total proved reserves as of December 31, 2008. During 2008, the Barnett Shale assets produced 181 bcfe, or 22%, of

 

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our total production. During 2008, we invested approximately $1.9 billion to drill 776 (600 net) wells in the Barnett Shale. For 2009, we anticipate spending approximately $1.275 billion, or 44% of our total budget for exploration and development activities in the Barnett Shale.

Appalachian Basin (including the Marcellus Shale).    Chesapeake’s Appalachian Basin proved reserves represented 1.569 tcfe, or 13%, of our total proved reserves as of December 31, 2008. During 2008, the Appalachian assets produced 36 bcfe, or 4%, of our total production. During 2008, we invested approximately $379 million to drill 161 (137 net) wells in the Appalachian Basin. For 2009, we anticipate spending approximately $145 million, or 5% of our total budget for exploration and development activities, net of carries, in the Appalachian Basin. StatoilHydro, our Marcellus Shale joint venture partner, will pay 75% of our drilling, completing and equipping costs in the play over the next few years. Of the total $2.125 billion drilling cost carry, we expect approximately $250 million will be applied in 2009.

Ark-La-Tex (including the Haynesville Shale).    Chesapeake’s Ark-La-Tex proved reserves represented 1.231 tcfe, or 10%, of our total proved reserves as of December 31, 2008. During 2008, the Ark-La-Tex assets produced 62 bcfe, or 7%, of our total production. During 2008, we invested approximately $429 million to drill 413 (136 net) wells in the Ark-La-Tex region. For 2009, we anticipate spending approximately $580 million, or 20% of our total budget for exploration and development activities, net of carries, in the Ark-La-Tex area. Plains Exploration & Production Company, our Haynesville Shale joint venture partner, will pay 50% of our drilling, completing and equipping costs in the play over the next few years. Of the total $1.65 billion drilling cost carry, $72 million was applied in 2008, and we expect approximately $425 million will be applied in 2009.

On February 20, 2009, we amended our joint venture agreement with Plains to provide Plains a one-time option, exercisable between June 15, 2010 and June 30, 2010, to reduce its maximum drilling cost carry obligation by $800 million in exchange for assigning us, effective December 31, 2010, 50% of its interest in the Haynesville joint venture properties. Chesapeake believes Plains’ cost basis in the properties that would be assigned to us upon exercise of the option could approximate $1.5 billion to $1.6 billion by December 31, 2010. If Plains exercises the option and has funded more than $850 million of its drilling cost carry as of December 31, 2010, we will be required to pay to Plains an amount equal to such excess. We will not be required to refund to Plains any of the $1.65 billion in cash consideration paid in July 2008 or any portion of the first $850 million in drilling cost carries to be paid by Plains.

South Texas and Texas Gulf Coast.    Chesapeake’s South Texas and Texas Gulf Coast proved reserves represented 943 bcfe, or 8%, of our total proved reserves as of December 31, 2008. During 2008, the South Texas and Texas Gulf Coast assets produced 71 bcfe, or 8%, of our total production. For 2008, we invested approximately $235 million to drill 65 (51 net) wells in the South Texas and Texas Gulf Coast regions. For 2009, we anticipate spending approximately $90 million, or 3% of our total budget for exploration and development activities in the South Texas and Texas Gulf Coast regions.

Permian and Delaware Basins.    Chesapeake’s Permian and Delaware Basin proved reserves represented 917 bcfe, or 8%, of our total proved reserves as of December 31, 2008. During 2008, the Permian assets produced 80 bcfe, or 10%, of our total production. During 2008, we invested approximately $841 million to drill 165 (95 net) wells in the Permian and Delaware Basins. For 2009, we anticipate spending approximately $200 million, or 7% of our total budget for exploration and development activities in the Permian and Delaware Basins.

 

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Drilling Activity

The following table sets forth the wells we drilled 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.

 

    2008     2007     2006  
    Gross   Percent     Net   Percent     Gross   Percent     Net   Percent     Gross   Percent     Net   Percent  

Development:

                       

Productive

  3,479   99 %   1,650   99 %   3,439   98 %   1,792   99 %   2,844   98 %   1,364   99 %

Non-productive

  40   1     13   1     53   2     10   1     47   2     13   1  
                                                           

Total

  3,519   100 %   1,663   100 %   3,492   100 %   1,802   100 %   2,891   100 %   1,377   100 %
                                                           

Exploratory:

                       

Productive

  142   90 %   63   90 %   177   99 %   116   99 %   128   98 %   71   99 %

Non-productive

  15   10     7   10     2   1     1   1     3   2     1   1  
                                                           

Total

  157   100 %   70   100 %   179   100 %   117   100 %   131   100 %   72   100 %
                                                           

The following table shows the wells we drilled by area:

 

     2008    2007    2006
     Gross Wells    Net Wells    Gross Wells    Net Wells    Gross Wells    Net Wells

Mid-Continent

   2,096    714    2,126    785    1,884    621

Barnett Shale

   776    600    512    410    244    187

Appalachian Basin

   161    137    431    374    319    272

Ark-La-Tex

   413    136    259    176    248    175

South Texas and Texas Gulf Coast

   65    51    90    67    138    102

Permian and Delaware Basins

   165    95    253    107    189    92
                             

Total

   3,676    1,733    3,671    1,919    3,022    1,449
                             

At December 31, 2008, we had 166 (83 net) wells in process.

Well Data

At December 31, 2008, we had interests in approximately 41,200 (22,813 net) producing wells, including properties in which we held an overriding royalty interest, of which 6,900 (3,840 net) were classified as primarily oil producing wells and 34,300 (18,973 net) were classified as primarily natural gas producing wells. Chesapeake operates approximately 23,800 of its 41,200 producing wells. During 2008, we drilled 1,819 (1,491 net) wells and participated in another 1,857 (242 net) wells operated by other companies. We operate approximately 86% of our current daily production volumes.

 

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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,  
     2008     2007     2006  

Net Production:

      

Natural gas (mmcf)

     775,424       654,969       526,459  

Oil (mbbls)

     11,220       9,882       8,654  

Natural gas equivalent (mmcfe)

     842,744       714,261       578,383  

Natural Gas and Oil Sales ($ in millions):

      

Natural gas sales

   $ 6,003     $ 4,117     $ 3,343  

Natural gas derivatives – realized gains (losses)

     267       1,214       1,269  

Natural gas derivatives – unrealized gains (losses)

     521       (139 )     467  
                        

Total natural gas sales

     6,791       5,192       5,079  
                        

Oil sales

     1,066       678       527  

Oil derivatives – realized gains (losses)

     (275 )     (11 )     (15 )

Oil derivatives – unrealized gains (losses)

     276       (235 )     28  
                        

Total oil sales

     1,067       432       540  
                        

Total natural gas and oil sales

   $ 7,858     $ 5,624     $ 5,619  
                        

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

      

Natural gas ($ per mcf)

   $ 7.74     $ 6.29     $ 6.35  

Oil ($ per bbl)

   $ 95.04     $ 68.64     $ 60.86  

Natural gas equivalent ($ per mcfe)

   $ 8.39     $ 6.71     $ 6.69  

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

      

Natural gas ($ per mcf)

   $ 8.09     $ 8.14     $ 8.76  

Oil ($ per bbl)

   $ 70.48     $ 67.50     $ 59.14  

Natural gas equivalent ($ per mcfe)

   $ 8.38     $ 8.40     $ 8.86  

Other Operating Income ($ per mcfe):

      

Natural gas and oil marketing

   $ 0.11     $ 0.10     $ 0.09  

Service operations

   $ 0.04     $ 0.06     $ 0.11  

Expenses ($ per mcfe):

      

Production expenses

   $ 1.05     $ 0.90     $ 0.85  

Production taxes

   $ 0.34     $ 0.30     $ 0.31  

General and administrative expenses

   $ 0.45     $ 0.34     $ 0.24  

Natural gas and oil depreciation, depletion and amortization

   $ 2.34     $ 2.57     $ 2.35  

Depreciation and amortization of other assets

   $ 0.21     $ 0.22     $ 0.18  

Interest expense (a)

   $ 0.27     $ 0.51     $ 0.52  

 

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

 

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Natural Gas and Oil Reserves

The tables below set forth information as of December 31, 2008 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 income tax (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.

 

     December 31, 2008
     Gas (mmcf)    Oil (mbbl)    Total (mmcfe)

Proved developed

     7,581,523      84,913      8,091,002

Proved undeveloped

     3,745,932      35,719      3,960,247
                    

Total proved

     11,327,455      120,632      12,051,249
                    
     Proved
Developed
   Proved
Undeveloped
   Total
Proved
     ($ in millions)

Estimated future net revenue (a)

   $ 27,433    $ 9,356    $ 36,789

Present value of estimated future net revenue (a)

   $ 13,274    $ 2,327    $ 15,601

Standardized measure (a) (b)

         $ 11,833

 

     Gas
(mmcf)
   Oil
(mbbl)
   Gas
Equivalent

(mmcfe)
   Percent of
Proved
Reserves
    Present
Value

($ in
millions)
 

Mid-Continent

   4,040,382    69,314    4,456,266    37 %   $ 5,807  

Barnett Shale

   2,934,292    153    2,935,208    24       3,990  

Appalachian Basin

   1,561,418    1,249    1,568,914    13       1,025  

Ark-La-Tex

   1,222,835    1,385    1,231,148    10       2,116  

South Texas and Texas Gulf Coast

   903,921    6,476    942,779    8       1,472  

Permian and Delaware Basins

   664,607    42,055    916,934    8       1,191  
                             

Total

   11,327,455    120,632    12,051,249    100 %   $ 15,601 (a)
                             

 

(a) 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 in effect at December 31, 2008. The prices used in our external and internal reserve reports yield weighted average wellhead prices of $41.60 per barrel of oil and $5.12 per mcf of natural gas. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity hedges in place at December 31, 2008. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. Estimated future net revenue and the present value thereof differ from future net cash flows and the standardized measure thereof only because the former do not include the effects of estimated future income tax expenses ($3.8 billion as of December 31, 2008).

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 without regard to income taxes. 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.

 

(b) The standardized measure of discounted future net cash flows is calculated in accordance with SFAS 69. 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.

 

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As of December 31, 2008, our reserve estimates included 3.960 tcfe of reserves classified as proved undeveloped (PUD). Of this amount, approximately 31%, 18% and 16% (by volume) were initially classified as PUDs in 2008, 2007 and 2006, respectively, and the remaining 35% were initially classified as PUDs prior to 2006. Of our proved developed reserves, 1.222 tcfe are non-producing, which are primarily “behind pipe” zones in producing wells.

The future net revenue attributable to our estimated proved undeveloped reserves of $9.4 billion at December 31, 2008, and the $2.3 billion present value thereof, have been calculated assuming that we will expend approximately $6.4 billion to develop these reserves. Net of joint venture cost carries, we have projected to incur $925 million in 2009, $2.5 billion in 2010, $1.7 billion in 2011 and $1.3 billion in 2012 and beyond, although the amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs, product 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. We do not believe any of these proved undeveloped reserves are contingent upon installation of additional infrastructure and we are not subject to regulatory approval other than routine permits to drill, which we expect to obtain in the normal course of business.

The estimates of our proved reserves disclosed in this report were prepared by Chesapeake’s internal staff 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. Chesapeake is responsible for the adequacy and accuracy of the estimates. We engaged five third-party engineering firms to audit portions of our reserve estimates comprising approximately 76% of our estimated proved reserves (by volume) at year-end 2008. A reserve audit is not the same as a financial audit and a reserve audit is less rigorous in nature than a reserve report prepared by an independent petroleum engineering firm containing its own estimate of reserves. The portion of our estimated proved reserves audited by each of our third-party engineering firms as of December 31, 2008 is presented below.

 

    % Audited
(by Volume)
 

Principal Properties Audited

Netherland, Sewell & Associates, Inc.

  42%  

Permian and Delaware Basins, Barnett Shale, portions of Ark-La-Tex, portions of Mid-Continent

Lee Keeling and Associates, Inc.   13%  

Portions of Mid-Continent, portions of South Texas/ Texas Gulf Coast

Data and Consulting Services,

Division of Schlumberger Technology Corporation

  8%  

Appalachian Basin

   

Ryder Scott Company, L.P.

  8%  

Portions of Mid-Continent, portions of South Texas/ Texas Gulf Coast

LaRoche Petroleum Consultants, Ltd.

  5%  

Portions of Mid-Continent, portions of Ark-La-Tex

Each of these third-party engineering firms opined that our estimates of proved reserves for those properties reviewed by such firm are, in the aggregate, reasonable, prepared in accordance with generally accepted petroleum engineering and evaluation principles, and conform to the SEC’s definition of proved reserves. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.

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

 

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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, 2008. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices.

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 Chesapeake’s 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. A change in price of $0.10 per mcf for natural gas and $1.00 per barrel for oil would result in a change in the December 31, 2008 present value of estimated future net revenue of our proved reserves of approximately $400 million and $55 million, respectively. The estimated future net revenue used in this analysis does not include the effects of future income taxes or hedging. The foregoing uncertainties are particularly true as to proved undeveloped reserves, which are inherently less certain than proved developed reserves and which comprise a significant portion of our proved reserves.

The company’s estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2008, 2007 and 2006, 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.

 

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Exploration and Development, Acquisition and Divestiture Activities

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

 

     December 31,
     2008     2007     2006
     ($ in millions)

Development and exploration costs:

      

Development drilling (a)

   $ 5,185     $ 4,402     $ 2,772

Exploratory drilling

     612       653       349

Geological and geophysical costs (b)

     314       343       154

Asset retirement obligation and other

     10       29       23
                      

Total

     6,121       5,427       3,298

Acquisition costs:

      

Proved properties

     355       671       1,175

Unproved properties (c)

     8,129       2,465       3,473

Deferred income taxes

     13       131       180
                      

Total

     8,497       3,267       4,828

Proceeds from divestitures:

      

Proved properties

     (2,433 )     (1,142 )    

Unproved properties

     (5,302 )          
                      

Total

   $ 6,883     $ 7,552     $ 8,126
                      

 

(a) Includes capitalized internal cost of $326 million, $243 million and $147 million, respectively.
(b) Includes capitalized internal cost of $26 million, $19 million and $13 million, respectively.
(c) Includes costs to acquire new leasehold and related capitalized interest.

Our development costs included $1.5 billion, $1.5 billion and $1.2 billion in 2008, 2007 and 2006, respectively, related to properties carried as proved undeveloped locations in the prior year’s reserve reports.

A summary of our exploration and development, acquisition and divestiture activities in 2008 by operating area is as follows:

 

    Gross
Wells
Drilled
  Net
Wells
Drilled
  Exploration
and
Development
  Acquisition of
Unproved
Properties
  Acquisition of
Proved
Properties (a)
  Sales of
Unproved
Properties
    Sales of
Proved
Properties
    Total  
    ($ in millions)  

Mid-Continent

  2,096   714   $ 2,338   $ 652   $ 94   $ (2,458 )   $ (2,322 )   $ (1,696 )

Barnett Shale

  776   600     1,899     1,598     161                 3,658  

Appalachian Basin

  161   137     379     897         (1,188 )     (39 )     49  

Permian and Delaware Basins

  165   95     841     325     11           (72 )     1,105  

Ark-La-Tex

  413   136     429     4,630     8     (1,656 )           3,411  

South Texas and Texas Gulf Coast

  65   51     235     27     94                 356  
                                                 

Total

  3,676   1,733   $ 6,121   $ 8,129   $ 368   $ (5,302 )   $ (2,433 )   $ 6,883  
                                                 

 

(a) Includes $13 million of deferred tax adjustments.

 

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Acreage

The following table sets forth as of December 31, 2008 the gross and net acres of both developed and undeveloped natural gas and oil leases which we hold. “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 leasehold which have not been exercised.

 

     Developed    Undeveloped    Total
     Gross Acres    Net Acres    Gross Acres    Net Acres    Gross Acres    Net Acres

Mid-Continent

   4,437,784    2,227,779    5,516,385    3,019,173    9,954,169    5,246,952

Barnett Shale

   136,938    111,129    272,281    198,545    409,219    309,674

Appalachian Basin

   574,287    542,448    5,536,546    4,338,124    6,110,833    4,880,572

Ark-La-Tex

   296,349    178,458    1,784,321    1,122,717    2,080,670    1,301,175

South Texas and Texas Gulf Coast

   317,649    185,166    222,562    151,664    540,211    336,830

Permian and Delaware Basins

   424,279    234,333    3,795,251    2,550,334    4,219,530    2,784,667
                             

Total

   6,187,286    3,479,313    17,127,346    11,380,557    23,314,632    14,859,870
                             

Marketing

Chesapeake Energy Marketing, Inc., one of our wholly-owned subsidiaries, provides natural gas and oil marketing services, including commodity price structuring, contract administration and nomination services for Chesapeake and its partners. We attempt to enhance the value of our natural gas production by aggregating natural gas to be sold to natural gas marketers 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 for sales of residue gas and natural gas liquids recovered after transportation and processing of our natural gas. These purchasers sell the residue gas and natural gas liquids based primarily on spot market prices. 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 2009, approximately 80% of our natural gas production was sold under short-term contracts at market-sensitive prices.

During 2008, sales to Eagle Energy Partners I, L.P. (Eagle) of $1.3 billion accounted for 12% of our total revenues (excluding gains (losses) on derivatives). In 2007, we sold our 33% limited partnership interest in Eagle Energy Partners I, L.P., which we first acquired in 2003, for proceeds of $124 million and a gain of $83 million. Management believes that the loss of this customer would not have a material adverse effect on our results of operations or our financial position. No other customer accounted for more than 10% of total revenues (excluding gains (losses) on derivatives) in 2008.

Our marketing activities constitute a reportable segment under SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information. See Note 15 of the notes to our consolidated financial statements in Item 8.

Midstream Operations

Chesapeake invests in gathering and processing facilities to complement our natural gas and oil operations in regions where we have significant production. By doing so, we are better able to manage the value received for and the costs of, gathering, treating and processing natural gas. We own and operate gathering systems in 15

 

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states throughout the primary areas of Chesapeake’s natural gas and oil producing regions. These systems are designed primarily to gather company production for delivery into major intrastate or interstate pipelines and are comprised of approximately 9,800 miles of gathering lines, treating facilities and processing facilities which provide service to approximately 12,500 wells.

We recently transferred substantially all of our midstream assets outside of Appalachia to a group of existing and newly formed wholly-owned subsidiaries, which we refer to as our “midstream subsidiaries”. The midstream subsidiaries, their parent, Chesapeake Midstream Partners, L.P. (CMP), and its principal operating subsidiary, Chesapeake Midstream Operating, L.L.C. (CMO), were each designated as unrestricted subsidiaries under Chesapeake’s indentures and revolving bank credit facility and were released from their guarantee obligations under Chesapeake’s indentures, revolving bank credit facility and secured hedging facilities. In October 2008, CMP and CMO entered into a $460 million revolving bank credit facility. They are using borrowings under the facility to fund capital expenditures associated with building additional natural gas gathering and other systems associated with Chesapeake’s drilling program and for general corporate purposes related to its midstream operations.

We have plans to sell either a minority interest in our midstream natural gas business or specific midstream assets. Proceeds from a midstream transaction would be used to fund a portion of the costs associated with building the midstream infrastructure in various shale plays, primarily in the Haynesville, Marcellus and Fayetteville shale plays.

Drilling

Securing available rigs is an integral part of the exploration process and therefore owning our own drilling company is a strategic advantage for Chesapeake. In 2001, Chesapeake formed its 100% owned drilling rig subsidiary, Nomac Drilling Corporation, with an investment of $26 million to build and refurbish five drilling rigs. As of December 31, 2008, Chesapeake had invested approximately $782 million to build or acquire 84 drilling rigs and to initiate the construction of 23 additional rigs. In a series of transactions in 2006, 2007 and 2008, our drilling subsidiaries sold 83 rigs for $677 million and subsequently leased back the rigs through 2018. The drilling rigs have depth ratings between 3,000 and 25,000 feet and range in drilling horsepower from 525 to 2,000. These drilling rigs are currently operating in Oklahoma, Texas, Arkansas, Louisiana and Appalachia. Chesapeake is the fourth largest drilling rig contractor in the U.S.

Trucking

In 2006, Chesapeake expanded its service operations 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. Our trucking business is utilized primarily to transport drilling rigs for both Chesapeake and third parties. Through this ownership, we are better able to manage the movement of our rigs. As of December 31, 2008, our fleet included 250 trucks and 15 cranes, which mainly service the Mid-Continent, Barnett Shale and Appalachian regions.

Compression

During the past few years Chesapeake has expanded its compression business. Our wholly-owned subsidiary, MidCon Compression, L.L.C., operates wellhead and system compressors to facilitate the transportation of our natural gas production. In a series of transactions in 2007 and 2008, MidCon sold a significant portion of its compressor fleet, consisting of 1,443 compressors, for $303 million and entered into a master lease agreement. These transactions were recorded as sales and operating leasebacks. Over the next two years, 625 new compressors are on order for approximately $240 million, and we intend to simultaneously enter into sale/leaseback transactions with financial counterparties as the compressors are delivered, if acceptable leasing arrangements are available to us.

 

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Seasonal Nature of Business

Generally, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can lessen seasonal demand fluctuations. World weather and resultant prices for LNG can also affect deliveries of competing LNG into this country from abroad, affecting the price of domestically produced natural gas.

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. The natural gas and oil industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported LNG. 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.

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 United States. 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 penalties for noncompliance. These regulatory burdens increase our cost of doing business and, consequently, affect our profitability.

Regulation of Natural Gas and Oil Operations.    Our exploration and production operations are subject to various types of regulation at the U.S. federal, state and local levels. Such regulation includes requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Very few of our natural gas and oil leases are located on federal lands. Other activities subject to regulation are:

 

   

the location of wells,

 

   

the method of drilling and completing wells,

 

   

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

 

   

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.

 

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Our operations 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 New Mexico, 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 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.

Chesapeake operates a number of natural gas gathering systems. The U.S. Department of Transportation and certain state agencies regulate the safety and operating aspects of the transportation and storage activities of these facilities. There is currently no price regulation of the company’s sales of oil, natural gas liquids and natural gas, although governmental agencies may elect in the future to regulate certain sales.

We do not anticipate that compliance with existing laws and regulations governing exploration, production and natural gas gathering will have a material adverse effect upon our capital expenditures, earnings or competitive position.

Environmental, Health and Safety Regulation.    The business operations of the company and its ownership and operation of natural gas and oil interests are subject to various federal, state and local environmental, health and safety laws and regulations pertaining to the release, emission or discharge of materials into the environment, the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes), the safety of employees, or otherwise relating to pollution, preservation, remediation or protection of human health and safety, natural resources, wildlife or the environment. We must take into account the cost of complying with environmental regulations in planning, designing, constructing, drilling, operating and abandoning wells and related surface facilities. In most instances, the regulatory frameworks relate to the handling of drilling and production materials, the disposal of drilling and production wastes, and the protection of water and air. In addition, our operations may require us to obtain permits for, among other things,

 

   

air emissions,

 

   

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.

Under federal, state and local laws, we could be required to remove or remediate previously disposed wastes, including wastes 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 response actions to address the release 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. The Environmental Protection Agency, state environmental agencies and, in some cases, third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such actions. Furthermore, certain wastes generated by our natural gas and oil operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements.

 

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Vast quantities of natural gas deposits exist in deep shale formations. It is customary in our industry to recover natural gas from these deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is the process of creating artificial cracks, or fractures, in shale formations deep underground where water, sand and other additives are pumped under high pressure into a shale gas formation. These deep shale gas formations are generally geologically separated and isolated from any fresh ground water supplies by thousands of feet of protective rock layers. 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 overlying aquifers. Legislative and regulatory efforts at the federal level and in some states have been made to render permitting and compliance requirements more stringent for hydraulic fracturing. Such efforts could have an adverse effect on our operations.

Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.

We have made and will continue to make expenditures to comply with environmental, health and safety regulations and requirements. These are necessary business costs in the natural gas and oil industry. Although we are not fully insured against all environmental, health and safety risks, and our insurance does not cover any penalties or fines that may be issued by a governmental authority, we maintain insurance coverage which we believe is customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental, health and safety laws and regulations, as well as claims for damages to property or persons resulting from company operations, could result in substantial costs and liabilities, including civil and criminal penalties, to Chesapeake. We believe we are in material compliance with existing environmental, health and safety regulations, and that, absent the occurrence of an extraordinary event, the effect of which cannot be predicted, any noncompliance will not have a material adverse effect on our business, financial position and results of operations.

Income Taxes

Chesapeake recorded income tax expense of $463 million in 2008 compared to income tax expense of $890 million in 2007 and $1.252 billion in 2006. Of the income tax expense recorded in 2008, $423 million is reflected as current income tax expense and $40 million is reflected as deferred income tax expense. The divestitures that closed during 2008 are projected to generate sufficient taxable income for the year to exhaust all our non-limited NOLs and result in a current tax liability for the tax year ended December 31, 2008. Of the $427 million decrease in 2008, $439 million was the result of the decrease in net income before taxes which was offset by $12 million as the result of an increase in the effective tax rate. Our effective income tax rate was 39% in 2008 compared to 38% in 2007 and 38.5% in 2006. Our effective tax rate fluctuates as a result of the impact of state income taxes and permanent differences between our accounting for certain revenue or expense items and their corresponding treatment for income tax purposes. We expect our effective income tax rate to be 39% in 2009.

At December 31, 2008, Chesapeake had federal income tax net operating loss (NOL) carryforwards of approximately $12 million. We also had approximately $3 million of alternative minimum tax (AMT) NOL carryforwards available as a deduction against future AMT income. The NOL carryforwards expire from 2019 through 2026. The value of the remaining carryforwards depends on the ability of Chesapeake to generate taxable income. In addition, for AMT purposes, only 90% of AMT income in any given year may be offset by AMT NOLs.

The ability of Chesapeake to utilize NOL carryforwards to reduce future federal taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the

 

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issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Chesapeake.

In the event of an ownership change (as defined for income tax purposes), Section 382 of the Code imposes an annual limitation on the amount of a corporation’s taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of the company multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains (as defined in the Code) inherent in the assets sold. Certain NOLs acquired through various acquisitions are also subject to limitations. The following table summarizes our net operating losses as of December 31, 2008 and any related limitations:

 

     Net Operating Losses
     Total    Limited    Annual
Limitation
     ($ in millions)

Net operating loss

   $ 12    $ 12    $ 7

AMT net operating loss

   $ 3    $ 3    $ 1

As of December 31, 2008, we do not believe that an ownership change has occurred. Future equity transactions by Chesapeake or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOLs. Following an ownership change, the amount of Chesapeake’s NOLs available for use each year will depend upon future events that cannot currently be predicted and upon interpretation of complex rules under Treasury regulations.

If less than the full amount of the annual limitation is utilized in any given year, the unused portion may be carried forward and may be used in addition to successive years’ annual limitation.

We expect to utilize our NOL carryforwards and other tax deductions and credits to offset taxable income in the future. However, there is no assurance that the Internal Revenue Service will not challenge these carryforwards or their utilization.

In June 2006, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109. FIN 48 provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS 109, Accounting for Income Taxes. FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. FIN 48 became effective for fiscal years beginning after December 15, 2006.

Chesapeake adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, Chesapeake recognized a $7 million liability for accrued interest associated with uncertain tax positions which was accounted for as a reduction in the January 1, 2007 balance of retained earnings, net of tax. At the date of adoption and at December 31, 2007, we had approximately $142 million and $133 million, respectively, of unrecognized tax benefits related to alternative minimum tax (AMT) associated with uncertain tax positions. As of December 31, 2008, the amount of unrecognized tax benefits related to regular tax liabilities and AMT associated with uncertain tax positions was $60 million. Of this amount, $48 million is related to regular tax liabilities and $12 million is related to AMT. These unrecognized tax benefits are associated with temporary differences. If these unrecognized tax benefits are disallowed and we are required to pay additional taxes, the reversal of the temporary differences associated with the regular tax liabilities will increase our tax basis which

 

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will increase our future tax deductions. Any AMT payments can be utilized as credits against future regular tax liabilities. The uncertain tax positions identified would not have a material effect on the effective tax rate. At December 31, 2008, we had an accrued liability of $3 million for interest related to these uncertain tax positions. Chesapeake recognizes interest related to uncertain tax positions in interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses.

Chesapeake files income tax returns in the U.S. federal jurisdiction and various state and local jurisdictions. With few exceptions, Chesapeake is no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years prior to 2005. The Internal Revenue Service (IRS) completed an examination of Chesapeake’s U.S. income tax returns for 2005 and 2006 in December 2008. This examination resulted in additional AMT liabilities of $1 million. These AMT liabilities will be utilized as credits against current regular tax liabilities. The adjustments in the examination did not result in a material change to our financial position, results of operations or cash flows.

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 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 $50 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 $350 million comprehensive general liability umbrella policy and a $100 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.

Facilities

Chesapeake owns an office complex in Oklahoma City and we continue to construct additional buildings in Oklahoma City. We also own or lease various field or administrative offices in the following locations:

 

   

Arkansas: Searcy and Little Rock

 

   

Illinois: Chicago

 

   

Kansas: Garden City

 

   

Kentucky: Gray, Elkhorn City, Hueysville, Debord and Langley

 

   

Louisiana: Cheneyville, Goldonna and Shreveport

 

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New Mexico: Carlsbad, Eunice, Hobbs and Lovington

 

   

New York: Horseheads

 

   

Oklahoma: Arkoma, Billings, El Reno, Elk City, Enid, Forgan, Hartshorne, Hinton, Kingfisher, Lindsay, Mayfield, Oklahoma City, Waynoka, Weatherford, Wilburton and Woodward

 

   

Pennsylvania: Mt. Morris, Mansfield and Towanda

 

   

Tennessee: Egan

 

   

Texas: Alvarado, Borger, Bryan, Cleburne, College Station, Dumas, Fort Worth, Garrison, Marshall, Midland, Ozona, Palestine, Pecos, Tyler, Victoria and Zapata

 

   

West Virginia: Branchland, Buckhannon, Chapmanville, Charleston, Cedar Grove, Clendenin, Hamlin, Jane Lew, Kermit, Shrewsbury, Tad and Teays Valley

Employees

Chesapeake had approximately 7,600 employees as of December 31, 2008, which includes approximately 2,750 employed by our service operations companies. As a result of our acquisition of Columbia Natural Resources, LLC in November 2005, we assumed a collective bargaining agreement with the United Steel Workers of America (USWA) which expired effective December 1, 2006, covering approximately 139 of our field employees in West Virginia and Kentucky. We continued to operate under the terms of the collective bargaining agreement while negotiating with the USWA. Contract negotiations began in October 2006 and have been mediated by the Federal Mediation and Conciliation Service. On May 4, 2007, we presented the USWA leadership our “last, best and final offer”. On December 7, 2007, the USWA membership voted to reject our offer. The company declared an impasse and, effective February 1, 2008, we implemented the terms of our offer with certain minor clarifications. Subsequently, the union filed three separate unfair labor practice charges. One charge was dismissed by the National Labor Relations Board and two charges were settled by mutual agreement. There have been no strikes, work stoppages or slowdowns since the expiration of the contract, although no assurances can be given that such actions will not occur.

Glossary of Natural Gas and Oil Terms

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

Bcf.    Billion cubic feet.

Bcfe.    Billion cubic feet of natural gas equivalent.

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

Bbtu.    One billion British thermal units.

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.

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.

 

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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.

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

Exploratory Well.    A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known 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.

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.

Infill Drilling.    Drilling wells between established producing wells on a lease; a drilling program to reduce the spacing between wells in order to increase production and/or recovery of in-place hydrocarbons from the lease.

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

Mbbl.    One thousand barrels of crude oil or other liquid hydrocarbons.

Mbtu.    One thousand btus.

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.

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.

 

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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 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%.

Productive Well.    A well that is producing oil or natural gas or that is capable of production.

Proved Developed Reserves.    Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional natural gas and oil expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production responses that increased recovery will be achieved.

Proved Reserves.    The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

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.    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 are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves may not include estimates attributable 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 tests in the area and in the same reservoir.

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. In calculating reserve replacement, we do not use unproved reserve quantities or proved reserve additions attributable to less than wholly-owned consolidated entities or investments accounted for using the equity method. 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.

 

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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 year-end prices, costs and statutory tax rates (adjusted for permanent differences) and a 10-percent annual discount rate.

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

Unproved Properties.    Properties with no proved reserves.

VPP.    A volumetric production payment represents an obligation of the seller of a property to deliver a specific volume of production, free and clear of all costs, to the purchaser of the property.

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.

 

ITEM 1A. Risk Factors

Natural gas and oil prices are volatile. A decline in prices could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for the natural gas and oil we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow from banks is subject to periodic redeterminations based on prices specified by our bank group at the time of redetermination. In addition, falling prices may result in ceiling test write-downs of our natural gas and oil properties, as described below in the risk factor “Price declines during 2008 resulted in a write-down of our asset carrying values and future price declines could result in additional write-downs in the future”.

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:

 

   

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

 

   

weather conditions;

 

   

the level of consumer demand;

 

   

the price and availability of alternative fuels;

 

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the proximity and capacity of natural gas pipelines and other transportation facilities;

 

   

the price and level of foreign imports;

 

   

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-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. Declines in natural gas and oil prices not only reduce revenue, but also reduce the amount of natural gas and oil that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. Further, natural gas and oil prices do not necessarily move in tandem. Because approximately 94% of our reserves at December 31, 2008 were natural gas reserves, we are more affected by movements in natural gas prices.

Our level of indebtedness may limit our financial flexibility.

As of December 31, 2008, we had long-term indebtedness of approximately $14.184 billion, with $3.474 billion of outstanding borrowings drawn under our revolving bank credit facility and $460 million of outstanding borrowings drawn under our midstream revolving bank credit facility. Our net indebtedness represented 43% of our total book capitalization at December 31, 2008. Following the February 2009 issuance of $1.425 billion of 9.5% Senior Notes due 2015, we had as of February 26, 2009 $1.630 billion outstanding under our revolving bank credit facility and $424 million outstanding under our midstream revolving bank credit facility.

Our level of indebtedness and preferred stock 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 pay dividends on our preferred stock 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;

 

   

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

 

   

changes in 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 and fees we pay on our revolving bank credit facilities.

We may incur additional debt, including secured indebtedness, or issue additional series of preferred stock in order to develop our properties and make future acquisitions. A higher level of indebtedness and/or additional preferred stock 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. 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, the number of shares of capital stock we have authorized, unissued and unreserved and our performance at the time we need capital.

 

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Chesapeake Midstream Operating’s midstream revolving bank credit facility contains a covenant restricting Chesapeake Midstream Partners from paying dividends or distributions to Chesapeake.

In addition, our bank borrowing base is subject to periodic redetermination. A lowering of our borrowing base could require us to repay indebtedness in excess of the borrowing base, or we might need to further secure the lenders with additional collateral.

The current financial crisis may have impacts on our business and financial condition that we cannot predict.

The continued credit crisis and related turmoil in the global economic financial systems may have an impact on our business and our financial condition, and we may face challenges if conditions in the economy and financial markets do not improve. Although we believe we have developed an operating and capital budget for 2009 and 2010 that will allow us to fund our business with internally generated cash flow, our cash flow from operations, our revolving bank credit facility 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. Our ability to access the capital markets has been restricted from time to time as a result of this crisis and may be restricted at a time when we would like, or need, to raise capital. The financial crisis may also limit the number of participants in our proposed asset monetization transactions or reduce the values we are able to realize in those transactions, making them uneconomic or harder or impossible to consummate. The economic situation could also adversely affect the collectability of our trade receivables and cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection. If our joint venture partners do not meet their obligations to fund a portion of our drilling costs in the Haynesville, Fayetteville or Marcellus Shale plays as agreed under our joint venture arrangements, or if our Haynesville joint venture partner, Plains Exploration & Production Company, exercises its option in June 2010 to reduce its drilling cost carry obligation by $800 million as described in Item 1 of this report under “Operating Areas”, we may be required to fund these expenditures from other sources or reduce our drilling activities. Additionally, the current economic situation could lead to reduced demand for natural gas and oil or lower prices for natural gas and oil or both, over the long term, which would have a negative impact on our revenues.

Price declines at the end of 2008 resulted in a write-down of our asset carrying values and further price declines could result in additional write-downs in the future.

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 prices for natural gas and oil at that date, adjusted for the impact of derivatives accounted for as cash flow hedges.

Natural gas and oil prices declined substantially throughout the second half of 2008 and were $5.71 per mcf and $44.61 per barrel on December 31, 2008. Our financial statements as of and for the year ended December 31, 2008 reflect an impairment of approximately $1.7 billion, net of income tax, of our natural gas and oil properties. We also had an after-tax non-cash impairment charge to certain investments and fixed assets of approximately $128 million for the 2008 fourth quarter as a result of lower asset valuation estimates.

Commodity prices in early 2009 have continued to trend lower. This and other factors could cause us to write down our natural gas and oil properties or other assets in the future and incur a non-cash charge against future earnings.

 

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Significant capital expenditures are required to replace our reserves.

Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, our revolving bank credit facility and debt and equity issuances. Beginning in late 2007, we have also engaged in significant asset monetization transactions. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of natural gas and oil, our success in developing and producing new reserves, the orderly functioning of credit and capital markets and our ability to complete additional planned asset monetization transactions. If revenues were to decrease as a result of lower natural gas and oil prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt, debt or equity or other methods of financing on an economic basis to meet these requirements.

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 33% of our total estimated proved reserves (by volume) at December 31, 2008 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. Our reserve estimates reflect that our production rate on producing properties will decline approximately 29% from 2009 to 2010. 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 prove to be lower 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. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

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. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.

At December 31, 2008, approximately 33% of our estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. These reserve estimates include the assumption that we will make significant capital expenditures to develop the reserves, including approximately $925 million in 2009. You should be aware that the estimated costs may not be accurate, development may not occur as scheduled and results may not be as estimated.

You should not assume that the present values referred to 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

 

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values are based on prices and costs as of the date of the estimates. The December 31, 2008 present value is based on weighted average natural gas and oil wellhead prices of $5.12 per mcf of natural gas and $41.60 per barrel of oil. 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 actual future net cash flows.

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.

Exploration and development drilling may not result in commercially productive reserves.

We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in new wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

   

increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment;

 

   

unexpected drilling conditions;

 

   

restricted access to land for drilling or laying pipeline;

 

   

pressure or irregularities in formations;

 

   

equipment failures or accidents;

 

   

adverse weather conditions; and

 

   

compliance with environmental and other governmental requirements.

Drilling results in our newer shale plays, primarily the Haynesville and Marcellus Shales, may be more uncertain than in shale plays that are more developed and have longer established production histories, such as the Barnett and Fayetteville Shales. Our experience with horizontal drilling in the Haynesville and Marcellus Shales, as well as the industry’s drilling and production history, is more limited than in the Barnett and Fayetteville Shale plays. Completion techniques that have proven to be successful in other shale formations to maximize recoveries are being used in the early development of the Haynesville and Marcellus Shales; however, we can provide no assurance of the ultimate success of these drilling and completion techniques.

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

As of December 31, 2008, we had leases on approximately 0.46 million and 1.25 million net acres, respectively, in the Haynesville and Marcellus Shale areas. A sizeable portion of this acreage is not currently held by production. Unless production in paying quantities is established on units containing these leases during their terms, the leases will expire. If our leases expire and we are unable to renew the leases, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various

 

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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 received for our natural gas and oil sales and require us to provide collateral for hedging liabilities.

In order to manage our exposure to price volatility in marketing our natural gas and oil, we enter into natural gas and oil price risk management arrangements for a portion of our expected production. Commodity price hedging 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;

 

   

there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or

 

   

the counterparties to our contracts fail to perform under the contracts.

All but three of our commodity price risk management counterparties require us to provide assurances of performance in the event that the counterparties’ mark-to-market exposure to us exceeds certain levels. Most of these arrangements allow us to minimize the potential liquidity impact of significant mark-to-market fluctuations by making collateral allocations from our revolving bank credit facility or directly pledging natural gas and oil properties, rather than posting cash or letters of credit with the counterparties. Future collateral requirements are uncertain, however, and will depend on the arrangements with our counterparties and highly volatile natural gas and oil prices.

Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities and market forces may change expected economics of acquisitions.

Our growth during the past few years is due in large part to acquisitions of exploration and production companies, producing properties and undeveloped leasehold. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future natural gas and oil prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. As a result of these factors, the purchase price we pay to acquire natural gas and oil properties may exceed the value we realize. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. When we make entity acquisitions, we may have transferee liability that is not fully indemnified. The company currently is a defendant in cases involving acquired companies where we may have no, or only limited, indemnification rights. In any such actions we could incur significant liability.

Finally, market forces beyond our control may change the expected economics of acquisitions. Due to the current financial crisis, decreases in natural gas prices and concerns about an oversupply of natural gas in the U.S., for example, market prices for undeveloped natural gas leasehold declined considerably during the second

 

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half of 2008. As a result, we have not closed on pending transactions with several significant Haynesville Shale mineral or leasehold owners and instead are seeking to acquire their interests at reduced prices. We have reached agreement with some of these owners and are still negotiating with others, including owners that have filed lawsuits against us alleging enforceable contracts providing for lease bonus payments above current market prices.

Lower natural gas and oil prices could negatively impact our ability to borrow.

Our revolving bank credit facility limits our borrowings to the lesser of the borrowing base and the total commitments. Currently both are $3.5 billion, although one lender, Lehman Brothers Commercial Bank, has not funded its share (2.1%) of our borrowings under the facility beginning in the third quarter of 2008, and we do not expect that it would fund any future borrowings. The borrowing base is determined periodically at the discretion of the banks and is based in part on natural gas and oil prices. Additionally, some of our indentures contain covenants limiting our ability to incur indebtedness in addition to that incurred under our revolving bank credit facility. These indentures limit our ability to incur additional indebtedness unless we meet one of two alternative tests. The first alternative is based on our adjusted consolidated net tangible assets (as defined in all of our indentures), which is determined using discounted future net revenues from proved natural gas and oil reserves as of the end of each year. The second alternative is based on the ratio of our adjusted consolidated EBITDA (as defined in the relevant indentures) to our adjusted consolidated interest expense (as defined in the relevant indentures) over a trailing twelve-month period. Currently, we are permitted to incur additional indebtedness under both debt incurrence tests. Lower natural gas and oil prices in the future could reduce our adjusted consolidated EBITDA, as well as our adjusted consolidated net tangible assets, and thus could reduce our ability to incur additional indebtedness.

Natural gas and oil drilling and producing operations can be hazardous and may expose us to 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 oil, natural gas, brine or well fluids, and other environmental hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. 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 exploration and production operations due to our generation, handling, and disposal of materials, including wastes and petroleum hydrocarbons. 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, some of which 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. 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.

 

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In addition, studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases”, may be impacting the Earth’s climate. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases. The U.S. Congress and various states have been evaluating climate-related legislation and other regulatory initiatives that would restrict emissions of greenhouse gases in areas in which we conduct business. Such restrictions may have an effect on demand for our products, particularly because natural gas is viewed by many as a readily available replacement for more carbon intensive sources of energy. Likewise, such restrictions may result in additional compliance obligations with respect to the release, capture and use of carbon dioxide that could have an adverse effect on our operations.

It is customary in our industry to use hydraulic fracturing – a process that creates a fracture extending from the well bore in a rock formation – to enable gas or oil to move more easily through the rock pores to a production well. Fractures are typically created through the injection of water and chemicals into the rock formation. Legislative and regulatory efforts at the federal level and in some states have been made to render permitting and compliance requirements more stringent for hydraulic fracturing. Such efforts could have an adverse effect on our operations.

Our ability to sell natural gas and/or receive market prices for our natural gas may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions.

If drilling in the Haynesville and Marcellus Shales continues to be successful, the amount of natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain pipeline projects that are planned for the Haynesville and Marcellus Shale areas may not occur for lack of financing. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our gas to interstate pipelines. 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. 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

We are involved in various disputes incidental to our business operations, including claims from royalty owners regarding volume measurements, post-production costs and prices for royalty calculations. In Tawney, et al. v. Columbia Natural Resources, Inc., Chesapeake’s wholly-owned subsidiary Chesapeake Appalachia, L.L.C., formerly known as Columbia Natural Resources, LLC (CNR), is a defendant in a class action lawsuit filed in

 

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2003 in the Circuit Court for Roane County, West Virginia by royalty owners. The plaintiffs allege that CNR underpaid royalties by improperly deducting post-production costs, failing to pay royalty on total volumes of natural gas produced and not paying a fair value for the natural gas produced from their leases. The plaintiff class consists of West Virginia royalty owners receiving royalties after July 31, 1990 from CNR. Chesapeake acquired CNR in November 2005, and its seller acquired CNR in 2003 from NiSource Inc. NiSource, a co-defendant in the case, indemnified Chesapeake against underpayment claims based on the use of fixed prices for natural gas production sold under certain forward sale contracts and other claims with respect to CNR’s operations prior to September 2003.

On January 27, 2007, the Circuit Court jury returned a verdict against the defendants of $404 million, consisting of $134 million in compensatory damages and $270 million in punitive damages. The jury found fraudulent conduct by the defendants with respect to the sales prices used to calculate royalty payments and with respect to the failure of CNR to disclose post-production deductions. The defendants appealed the judgment and on May 22, 2008, the West Virginia Supreme Court of Appeals refused to hear the appeal. On October 22, 2008, the parties in the Tawney matter entered into a settlement agreement providing for the establishment of a settlement fund of $380 million. The Circuit Court for Roane County, West Virginia approved the settlement following a fairness hearing on November 22, 2008, and entered an order to discharge the judgment on January 21, 2009. Chesapeake’s share of the settlement fund was approximately $41 million, which amount had previously been fully reserved. The Circuit Court retains continuing jurisdiction over the case during the claims administration process in which the settlement amount is distributed to the members of the plaintiff class.

Chesapeake is subject to other legal proceedings and claims which arise in the ordinary course of business. In our opinion, the final resolution of these proceedings and claims will not have a material effect on the company.

 

ITEM 4.    Submission of Matters to a Vote of Security Holders

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

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:

 

     Common Stock
     High    Low

Year ended December 31, 2008:

     

Fourth Quarter

   $ 35.46    $ 9.84

Third Quarter

     74.00      31.15

Second Quarter

     68.10      45.25

First Quarter

     49.87      34.42

Year ended December 31, 2007:

     

Fourth Quarter

   $ 41.19    $ 34.90

Third Quarter

     37.55      31.38

Second Quarter

     37.75      30.88

First Quarter

     31.83      27.27

At February 26, 2009, there were approximately 2,025 holders of record of our common stock and 455,500 approximately beneficial owners.

Dividends

The following table sets forth the amount of dividends per share declared on Chesapeake common stock during 2008 and 2007:

 

     2008    2007

Fourth Quarter

   $ 0.075    $ 0.0675

Third Quarter

     0.075      0.0675

Second Quarter

     0.075      0.0675

First Quarter

     0.0675      0.06

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 revolving bank credit facility and the indentures governing certain of our outstanding senior notes contain restrictions on our ability to declare and pay cash dividends. Under the revolving bank credit facility and these indentures, we may not pay any cash dividends on our common or preferred stock if an event of default has occurred. These indentures further restrict cash dividends if we have not met one of the two debt incurrence tests set forth in the indentures, or if immediately after giving effect to the dividend payment, we have paid total dividends and made other restricted payments in excess of the permitted amounts. As of December 31, 2008, our coverage ratio for purposes of the debt incurrence test under the relevant indentures was 8.7 to 1, compared to a minimum of 2.25 to 1 required in such indentures. Our adjusted consolidated net tangible assets exceeded 200% of our total indebtedness, as required by the second debt incurrence test in these indentures, by approximately $1.0 billion.

 

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The certificates of designation for our 5.00% Cumulative Convertible Preferred Stock (Series 2005), our 4.50% Cumulative Convertible Preferred Stock, our 5.00% Cumulative Convertible Preferred Stock (Series 2005B), our 4.125% Cumulative Convertible Preferred Stock and our 6.25% Mandatory Convertible 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 such series of our preferred stock.

Purchases of Common Stock

The following table presents information about repurchases of our common stock during the three months ended December 31, 2008:

 

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, 2008 through October 31, 2008

   24,174    $ 22.388      

November 1, 2008 through November 30, 2008

   15,976    $ 20.658      

December 1, 2008 through December 31, 2008

   5,385    $ 15.829      
                     

Total

   45,535    $ 21.005      
                     

 

(a) Includes the deemed surrender to the company of 5,868 shares of common stock to pay the exercise price in connection with the exercise of employee stock options and the surrender to the company of 39,667 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 purposes of the company contributions. There are no other repurchase plans or programs currently authorized by the Board of Directors.

 

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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, 2008, 2007, 2006, 2005 and 2004. The data are derived from our audited consolidated financial statements revised to reflect the reclassification of certain items. Changes in annual average natural gas and oil prices and increased production from drilling and acquisition activity in recent years have impacted comparability between years. See Note 10 of the notes to our consolidated financial statements. The table should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements, including the notes, appearing in Items 7 and 8 of this report.

 

     Years Ended December 31,  
     2008     2007     2006     2005     2004  
     ($ in millions, except per share data)  

Statement of Operations Data:

          

Revenues:

          

Natural gas and oil sales

   $ 7,858     $ 5,624     $ 5,619     $ 3,273     $ 1,936  

Natural gas and oil marketing sales

     3,598       2,040       1,577       1,392       773  

Service operations revenue

     173       136       130              
                                        

Total revenues

     11,629       7,800       7,326       4,665       2,709  
                                        

Operating costs:

          

Production expenses

     889       640       490       317       205  

Production taxes

     284       216       176       208       104  

General and administrative expenses

     377       243       139       64       37  

Natural gas and oil marketing expenses

     3,505       1,969       1,522       1,358       755  

Service operations expense

     143       94       68              

Natural gas and oil depreciation, depletion and amortization

     1,970       1,835       1,359       894       582  

Depreciation and amortization of other assets

     177       154       104       51       29  

Impairment of natural gas and oil properties and other fixed assets

     2,830                          

Employee retirement expense

                 55              

Provision for legal settlements

                             5  
                                        

Total operating costs

     10,175       5,151       3,913       2,892       1,717  
                                        

Income from operations

     1,454       2,649       3,413       1,773       992  
                                        

Other income (expense):

          

Interest and other income

     (11 )     15       26       10       5  

Interest expense

     (314 )     (406 )     (301 )     (220 )     (167 )

Gain (loss) on repurchases or exchanges of Chesapeake debt

     237                   (70 )     (25 )

Impairment of investments

     (180 )                        

Gain on sale of investments

           83       117              
                                        

Total other income (expense)

     (268 )     (308 )     (158 )     (280 )     (187 )
                                        

Income before income taxes and cumulative effect of accounting change

     1,186       2,341       3,255       1,493       805  

Income tax expense:

          

Current

     423       29       5              

Deferred

     40       861       1,247       545       290  
                                        

Total income tax expense

     463       890       1,252       545       290  
                                        

Net Income

     723       1,451       2,003       948       515  

Preferred stock dividends

     (33 )     (94 )     (89 )     (42 )     (40 )

Loss on conversion/exchange of preferred stock

     (67 )     (128 )     (10 )     (26 )     (36 )
                                        

Net income available to common shareholders

   $ 623     $ 1,229     $ 1,904     $ 880     $ 439  
                                        

Earnings per common share:

          

Basic

   $ 1.16     $ 2.69     $ 4.78     $ 2.73     $ 1.73  

Assuming dilution

   $ 1.14     $ 2.62     $ 4.35     $ 2.51     $ 1.53  

Cash dividends declared per common share

   $ 0.2925     $ 0.2625     $ 0.23     $ 0.195     $ 0.17  

Cash Flow Data:

          

Cash provided by operating activities

   $ 5,236     $ 4,932     $ 4,843     $ 2,407     $ 1,432  

Cash used in investing activities

     9,844       7,922       8,942       6,921       3,381  

Cash provided by financing activities

     6,356       2,988       4,042       4,567       1,915  

Balance Sheet Data (at end of period):

          

Total assets

   $ 38,444     $ 30,734     $ 24,417     $ 16,118     $ 8,245  

Long-term debt, net of current maturities

     14,184       10,950       7,376       5,490       3,075  

Stockholders’ equity

     16,297       12,130       11,251       6,174       3,163  

 

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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,  
     2008     2007     2006  

Net Production:

      

Natural gas (mmcf)

     775,424       654,969       526,459  

Oil (mbbls)

     11,220       9,882       8,654  

Natural gas equivalent (mmcfe)

     842,744       714,261       578,383  

Natural Gas and Oil Sales ($ in millions):

      

Natural gas sales

   $ 6,003     $ 4,117     $ 3,343  

Natural gas derivatives – realized gains (losses)

     267       1,214       1,269  

Natural gas derivatives – unrealized gains (losses)

     521       (139 )     467  
                        

Total natural gas sales

     6,791       5,192       5,079  
                        

Oil sales

     1,066       678       527  

Oil derivatives – realized gains (losses)

     (275 )     (11 )     (15 )

Oil derivatives – unrealized gains (losses)

     276       (235 )     28  
                        

Total oil sales

     1,067       432       540  
                        

Total natural gas and oil sales

   $ 7,858     $ 5,624     $ 5,619  
                        

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

      

Natural gas ($ per mcf)

   $ 7.74     $ 6.29     $ 6.35  

Oil ($ per bbl)

   $ 95.04     $ 68.64     $ 60.86  

Natural gas equivalent ($ per mcfe)

   $ 8.39     $ 6.71     $ 6.69  

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

      

Natural gas ($ per mcf)

   $ 8.09     $ 8.14     $ 8.76  

Oil ($ per bbl)

   $ 70.48     $ 67.50     $ 59.14  

Natural gas equivalent ($ per mcfe)

   $ 8.38     $ 8.40     $ 8.86  

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

      

Natural gas and oil marketing

   $ 93     $ 71     $ 55  

Service operations

   $ 30     $ 42     $ 62  

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

      

Natural gas and oil marketing

   $ 0.11     $ 0.10     $ 0.09  

Service operations

   $ 0.04     $ 0.06     $ 0.11  

Expenses ($ per mcfe):

      

Production expenses

   $ 1.05     $ 0.90     $ 0.85  

Production taxes

   $ 0.34     $ 0.30     $ 0.31  

General and administrative expenses

   $ 0.45     $ 0.34     $ 0.24  

Natural gas and oil depreciation, depletion and amortization

   $ 2.34     $ 2.57     $ 2.35  

Depreciation and amortization of other assets

   $ 0.21     $ 0.22     $ 0.18  

Interest expense (b)

   $ 0.27     $ 0.51     $ 0.52  

Interest Expense ($ in millions):

      

Interest expense

   $ 235     $ 365     $ 301  

Interest rate derivatives – realized (gains) losses

     (6 )     1       2  

Interest rate derivatives – unrealized (gains) losses

     85       40       (2 )
                        

Total interest expense

   $ 314     $ 406     $ 301  
                        

Net Wells Drilled

     1,733       1,919       1,449  

Net Producing Wells as of the End of Period

     22,813       21,404       19,079  

 

(a) Includes revenue and operating costs and excludes depreciation and amortization of other assets.
(b) 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.

 

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We manage our business as three separate operational segments: exploration and production; marketing; and service operations, which is comprised of our wholly-owned drilling and trucking operations. We refer you to Note 14 of the notes to our consolidated financial statements appearing in Item 8 of this report, which summarizes by segment our net income and capital expenditures for 2008, 2007 and 2006 and our assets as of December 31, 2008, 2007 and 2006.

Executive Summary

We are the largest independent producer of natural gas in the United States. We own interests in approximately 41,200 producing oil and natural gas wells that are currently producing approximately 2.3 bcfe per day, 92% of which is natural gas. Our strategy is focused on discovering, acquiring and developing conventional and unconventional natural gas reserves onshore in the U.S., primarily in the “Big 4” natural gas shale plays: the Barnett Shale in the Fort Worth Basin of north-central Texas, the Haynesville Shale in the Ark-La-Tex area of northwestern Louisiana and East Texas, the Fayetteville Shale in the Arkoma Basin of central Arkansas and the Marcellus Shale in the northern Appalachian Basin of West Virginia, Pennsylvania and New York. We also have substantial operations in various other plays, both conventional and unconventional, in the Mid-Continent, Appalachian Basin, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast and Ark-La-Tex regions of the United States.

During 2008, Chesapeake continued the industry’s most active drilling program drilling 1,819 gross (1,491 net) operated wells and participating in another 1,857 gross (242 net) wells operated by other companies. The company’s drilling success rate was 99% for company-operated wells and 98% for non-operated wells. Also during 2008, we invested $5.043 billion in operated wells (using an average of 145 operated rigs) and $754 million in non-operated wells (using an average of 110 non-operated rigs) for total drilling, completing and equipping costs of $5.797 billion.

Chesapeake began 2008 with estimated proved reserves of 10.879 tcfe and ended the year with 12.051 tcfe, an increase of 1.172 tcfe, or 11%. During 2008, we replaced 843 bcfe of production with an internally estimated 2.015 tcfe of new proved reserves, for a reserve replacement rate of 239%. Reserve replacement through the drillbit was 2.545 tcfe, or 302% of production, including 1.248 tcfe of positive performance revisions and 298 bcfe of negative revisions resulting from natural gas and oil price decreases between December 31, 2007 and December 31, 2008. Reserve replacement through the acquisition of proved reserves was 172 bcfe. During 2008, we divested 702 bcfe of estimated proved reserves. Our annual decline rate on producing properties is projected to be 29% from 2009 to 2010, 18% from 2010 to 2011, 14% from 2011 to 2012, 11% from 2012 to 2013 and 9% from 2013 to 2014. Our percentage of proved undeveloped reserve additions to total proved reserve additions was approximately 2% in 2008, 29% in 2007 and 38% in 2006. Based on our current drilling schedule and budget, we expect that virtually all of the proved undeveloped reserves added in 2008 will begin producing within the next three to five years. Generally, proved developed reserves are producing at the time they are added or will begin producing within one year.

Since 2000, Chesapeake has invested $12.6 billion in new leasehold (net of divestitures) and 3-D seismic acquisitions and now owns the largest combined inventories of onshore leasehold (15 million net acres) and 3-D seismic (22 million acres) in the U.S. On this leasehold, the company has approximately 36,000 net drillsites representing more than a 10-year inventory of drilling projects.

Business Strategy

Our exploration, development and acquisition activities require us to make substantial operating and capital expenditures. Through the middle of 2008, we increased our capital expenditure budget for 2008 and 2009 several times in response to higher leasehold acquisition costs and in order to accelerate leasehold acquisition and drilling in the Haynesville Shale and other plays. During the second half of 2008, in response to a significant decrease in natural gas prices, deteriorating global economic conditions and outlook and concerns about a

 

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potential oversupply of natural gas in the U.S. market, we significantly reduced our planned capital expenditures through year-end 2010 in order to bring our planned operating and capital expenditures within our anticipated internally generated cash flow. Our current budgeted capital expenditures for drilling, leasehold and producing property acquisitions, geophysical costs, and additions to midstream, compression and other property and equipment are $4.150 billion to $4.675 billion in 2009 and $4.550 billion to $5.175 billion in 2010.

Cash flow from operations is our primary source of liquidity used to fund operating expenses and capital expenditures. Our $3.5 billion revolving bank credit facility and our $460 million midstream revolving bank credit facility, discussed more fully below, provide us with additional liquidity. In response to the difficulties faced by several financial institutions and to ensure we had ample liquidity available, we borrowed the remaining capacity under our revolving bank credit facility at the end of the third quarter of 2008. As a result, we had borrowings of $3.474 billion and letters of credit of $15 million outstanding under that facility as of December 31, 2008. As of December 31, 2008, we had borrowings of $460 million under the midstream credit facility.

During 2008, we relied on capital markets financings and asset monetization transactions, such as sales of producing properties, undeveloped acreage and non-strategic assets, joint venture arrangements and volumetric production payment, or VPP, transactions to provide us with additional capital. Since March 31, 2008, these types of transactions have provided approximately $12.1 billion of new capital, and up to $4.6 billion of our future drilling and completion costs in the Haynesville, Fayetteville and Marcellus Shales will be funded by our joint venture partners. These transactions are summarized below:

 

   

From April through July of 2008, we issued 51.75 million shares of our common stock, $800 million of our 7.25% Senior Notes due 2018 and $1.380 billion of our 2.25% Contingent Convertible Senior Notes due 2038, resulting in aggregate net proceeds to us of $4.734 billion. The availability of any additional capital from the public or private markets is uncertain at this time.

 

   

In May, August and December of 2008, we completed three separate VPP transactions involving approximately 285 bcfe of proved reserves and net production (at the time of sale) of 153 mmcfe per day from wells in Texas, Oklahoma and Kansas, resulting in aggregate net proceeds to us of $1.6 billion.

 

   

In July of 2008, we entered into a joint venture with Plains Exploration & Production Company to develop our Haynesville Shale leasehold, under the terms of which (1) Plains acquired a 20% interest in our approximately 550,000 net acres of Haynesville Shale leasehold for $1.65 billion in cash, (2) Plains agreed to fund 50% of our 80% share of the costs associated with drilling and completing future Haynesville Shale joint venture wells over a multi-year period, up to an additional $1.65 billion and (3) Plains will have the right to a 20% participation in any additional leasehold we acquire in the Haynesville Shale. Subsequently, in February 2009, we amended the joint venture to provide Plains a one-time option in June 2010 to reduce its obligation to fund our drilling and completion costs by $800 million in exchange for assigning us 50% of its interest in the Haynesville joint venture properties.

 

   

In August of 2008, we sold 90,000 net acres of leasehold and producing natural gas properties with net production (at the time of sale) of 50 mmcfe per day in the Arkoma Basin Woodford Shale play in Oklahoma to BP America Inc. for $1.7 billion in cash.

 

   

In September of 2008, we entered into a joint venture with BP America Inc. to develop our Fayetteville Shale leasehold, under the terms of which (1) BP acquired a 25% interest in our approximately 540,000 net acres of Fayetteville Shale leasehold for $1.1 billion in cash, (2) BP agreed to fund 100% of our 75% share of the costs associated with drilling and completing future Fayetteville Shale joint venture wells over a multi-year period, up to an additional $800 million and (3) BP will have the right to a 25% participation in any additional leasehold we acquire in the Fayetteville Shale.

 

   

In November of 2008, we entered into a joint venture with a U.S. subsidiary of StatoilHydro ASA, under the terms of which StatoilHydro acquired a 32.5% interest in our approximately 1.8 million net acres of Marcellus Shale leasehold for $1.25 billion in cash, (2) StatoilHydro agreed to fund 75% of

 

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our 67.5% share of the costs associated with drilling and completing future Marcellus Shale joint venture wells over a multi-year period, up to an additional $2.125 billion and (3) StatoilHydro will have the right to a 32.5% participation in any additional leasehold we acquire in the Marcellus Shale. Additionally, Chesapeake and StatoilHydro are evaluating opportunities for an international strategic alliance to jointly explore unconventional natural gas opportunities worldwide.

During the fourth quarter of 2008, we privately exchanged $765 million in aggregate principal amount of our 2.75% Contingent Convertible Senior Notes due 2035, our 2.50% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038 for an aggregate of 23,913,203 shares of our common stock. Our net debt as a percentage of total capitalization (total capitalization is the sum of net debt less cash on hand and stockholders’ equity) was 43% as of December 31, 2008 and 47% as of December 31, 2007. The average maturity of our long-term debt as of December 31, 2008 was over eight years with an average interest rate of approximately 5.6%. No scheduled principal payments are required under our senior notes until 2013 when $864 million is due.

We plan to continue to evaluate asset monetization transactions in order to create additional value from our proved and unproved properties and to increase our financial flexibility. Management believes that our leasehold and development joint ventures and various asset monetization programs benefit the company by improving our asset base, reducing our financial risk, decreasing our DD&A rate and increasing our profitability per unit of production, thereby increasing our returns on capital and advancing future value creation. We may also consider alternative sources of public or private investment in the company or its subsidiaries. While we believe that our anticipated internally generated cash flow, cash resources and other sources of liquidity will allow us to fully fund our 2009 and 2010 operating and capital expenditure requirements, further deterioration of the economy and other factors could require us to fund these expenditures from monetization transactions or further curtail our spending.

Liquidity and Capital Resources

Sources and Uses of Funds

Cash flow from operations is a significant source of liquidity used to fund operating expenses and capital expenditures. Cash provided by operating activities was $5.236 billion in 2008, compared to $4.932 billion in 2007 and $4.843 billion in 2006. The $304 million increase from 2007 to 2008 was primarily due to higher volumes of natural gas and oil production. The $89 million increase from 2006 to 2007 was primarily due to higher volumes of natural gas and oil production. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding non-cash items, such as depreciation, depletion and amortization, deferred income taxes and unrealized gains and (losses) on derivatives. See the discussion below under Results of Operations.

Changes in market prices for natural gas and oil directly impact the level of our cash flow from operations. To mitigate the risk of declines in natural gas or oil prices and to provide more predictable future cash flow from operations, we currently have hedged through swaps and collars 78% of our expected remaining natural gas and oil production in 2009 and 48% of our expected natural gas and oil production in 2010 at average prices of $7.71 and $9.02 per mcfe, respectively. Our natural gas and oil hedges as of December 31, 2008 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 hedging positions.

As of December 31, 2008, we had a net natural gas and oil derivative asset of $1.305 billion. We have arrangements with our hedging counterparties that allow us to minimize the potential liquidity impact of significant mark-to-market fluctuations in the value of our natural gas and oil hedges by making collateral allocations from our bank credit facility or directly pledging natural gas and oil properties, rather than posting cash or letters of credit with the counterparties.

 

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Our $3.5 billion bank credit facility, our $460 million midstream bank credit facility and cash and cash equivalents are other sources of liquidity. Following the February 2009 issuance of $1.425 billion of 9.5% Senior Notes due 2015, there was as of February 26, 2009 $1.864 billion of borrowing capacity available under the revolving bank credit facility and $36 million of borrowing capacity under the midstream credit facility. We use the facilities and cash on hand to fund daily operating activities and acquisitions as needed. We borrowed $13.3 billion and repaid $11.3 billion in 2008, we borrowed $7.9 billion and repaid $6.2 billion in 2007, and we borrowed $8.4 billion and repaid $8.3 billion in 2006 under our bank credit facilities. A substantial portion of our natural gas and oil properties are not currently pledged under debt or hedging arrangements and therefore are available to be pledged as additional collateral under our revolving bank credit facility if needed based on our periodic borrowing base and collateral redeterminations. Accordingly, we believe our borrowing capacity will not be reduced associated with such periodic redeterminations.

On April 2, 2008, we issued 23 million shares of our common stock in a public offering at a price of $45.75 per share, and on July 15, 2008, we issued 28.75 million shares of common stock in a public offering at a price of $57.25 per share. On May 20, 2008 we completed public offerings of $800 million of our 7.25% Senior Notes due 2018 and $1.380 billion of our 2.25% Contingent Convertible Senior Notes due 2038. These four offerings resulted in aggregate net proceeds to us of approximately $4.734 billion, which we used to fund the redemption of our 7.75% Senior Notes due 2015 and to temporarily repay indebtedness outstanding under our revolving bank credit facility. The following table reflects the proceeds from sales of securities we issued in 2008, 2007 and 2006 (in millions):

 

     2008    2007    2006
     Total
Proceeds
   Net
Proceeds
   Total
Proceeds
   Net
Proceeds
   Total
Proceeds
   Net
Proceeds

Common stock

   $ 2,698    $ 2,598    $    $    $ 1,800    $ 1,759

Contingent convertible senior notes

     1,380      1,349      1,650      1,607          

Senior notes

     800      787                1,799      1,755

Convertible preferred stock

                         575      558
                                         

Total

   $ 4,878    $ 4,734    $ 1,650    $ 1,607    $ 4,174    $ 4,072
                                         

In May 2008, we sold a portion of our proved reserves in certain producing assets in Texas, Oklahoma and Kansas in a VPP transaction for proceeds of approximately $616 million, net of transaction costs. We completed another VPP transaction in August 2008, when we sold a portion of our proved reserves in certain producing assets in the Anadarko Basin of Oklahoma for proceeds of approximately $594 million, net of transaction costs. Also, in December 2008, we sold certain long-lived producing assets in the Anadarko and Arkoma Basins in a VPP transaction for proceeds of approximately $412 million, net of transaction costs. Approximately, $43 million of the proceeds are being held in escrow until post-closing adjustments have been finalized. In August 2008, we sold leasehold and producing natural gas properties in the Arkoma Basin Woodford Shale play in Oklahoma for $1.7 billion in cash.

In the second half of 2008, the company entered into three joint venture arrangements covering three of the company’s Big 4 shale plays. In the joint ventures, the company has collaborated with other leading energy companies to accelerate the development of the company’s properties in the Haynesville Shale, the Fayetteville Shale and the Marcellus Shale. In total, we sold leasehold and producing property assets in which we had a cost basis of approximately $1.2 billion to these three joint venture partners for total cash consideration of $4.0 billion and up to $4.6 billion of future drilling cost carries while we retained a majority interest in each joint venture. The drilling cost carries of up to approximately $4.2 billion that remain unused as of December 31, 2008 will be extremely valuable in the years ahead by enabling the company to develop reserves in these joint venture shale plays at greatly reduced costs. We are also considering opportunities for other joint venture transactions to develop our properties.

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 other investing activities for 2008, 2007 and 2006.

 

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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, higher 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.

We paid dividends on our common stock of $148 million, $115 million and $87 million in 2008, 2007 and 2006, respectively. The Board of Directors increased the quarterly dividend on common stock from $0.0675 to $0.075 per share beginning with the dividend paid in July 2008. Dividends paid on our preferred stock decreased to $35 million in 2008 from $95 million in 2007 and $88 million in 2006 as a result of conversions and exchanges of preferred stock into common stock during 2008 and 2007.

In 2008, holders of our 4.5% cumulative convertible preferred stock and our 5.0% (Series 2005B) cumulative preferred stock exchanged 891,100 shares and 3,654,385 shares for 2,227,750 shares and 10,443,642 shares of common stock, respectively, in privately negotiated exchanges. The exchanges resulted in a loss of $67 million. In 2007, holders of our 5.0% (Series 2005) cumulative convertible preferred stock and 6.25% mandatory convertible preferred stock exchanged 4,535,880 shares and 2,156,184 shares for 19,038,891 and 17,367,823 shares of common stock, respectively, in public exchange offers. The exchanges resulted in a loss $128 million.

We received $9 million, $15 million and $73 million from the exercise of employee and director stock options in 2008, 2007 and 2006, respectively. We paid $5 million, $0 and $86 million to purchase treasury stock in 2008, 2007 and 2006, respectively. Of these amounts, $5 million and $11 million were used to fund our matching contribution to our 401(k) and deferred compensation plans in 2008 and 2006, respectively. The remaining $75 million in 2006 was used to purchase shares of common stock to be used upon the exercise of stock options under certain stock option plans.

In 2008, 2007 and 2006, we paid $167 million, $91 million and $87 million, respectively, to settle a portion of the derivative liabilities assumed in our 2005 acquisition of Columbia Natural Resources, LLC.

SFAS 123(R) requires tax benefits resulting from stock-based compensation deductions in excess of amounts reported for financial reporting purposes to be reported as cash flows from financing activities. In 2008, 2007 and 2006, we reported a tax benefit from stock-based compensation of $43 million, $20 million and $88 million, respectively.

Outstanding payments from certain disbursement accounts in excess of funded cash balances where no legal right of set-off exists increased by $330 million, decreased by $98 million and increased by $70 million in 2008, 2007 and 2006, respectively. All disbursements are funded on the day they are presented to our bank using available cash on hand or draws on our revolving bank credit facility.

Credit Risk

A significant portion of our liquidity is concentrated in both cash and cash equivalents and derivative instruments. On December 31, 2008, our cash and cash equivalents were invested in money market funds with investment grade ratings. A significant portion of these funds was invested at the close of business on September 19, 2008, and is protected under the U.S. Treasury Department’s Temporary Guarantee Program. The remaining funds were spread among several counterparties to mitigate risk.

Derivative instruments enable us to hedge a portion of our exposure to natural gas and oil prices and interest rate volatility. These arrangements expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers and spread our instruments among multiple counterparties such that no single counterparty represents a material credit risk to the company. Recently there have been concerns about the ability of certain counterparties to continue to meet their financial obligations. We monitor the creditworthiness of all our counterparties and do not believe a failure by a counterparty would have a material negative impact on our liquidity.

 

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Our accounts receivable are primarily from purchasers of natural gas and oil ($738 million at December 31, 2008) and exploration and production companies which own interests in properties we operate ($424 million at December 31, 2008). 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 parental guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.

Investing Activities

Cash used in investing activities increased to $9.844 billion in 2008, compared to $7.922 billion in 2007 and $8.942 billion in 2006. We have continued our active drilling program and our acquisitions are focused on leasehold and property acquisitions needed for planned natural gas and oil development. Our investing activities during the past two years reflect our increasing focus on acquiring unproved leasehold and converting our resource inventory into production, redeploying our capital by selling natural gas and oil properties with lower rates of return and increasing our investment in properties with higher return potential, and investing in drilling rigs, midstream systems, compressors and other property and equipment to support our natural gas and oil exploration, development and production activities. The following table shows our cash used in (provided by) investing activities during 2008, 2007 and 2006 (in millions):

 

Natural Gas and Oil Investing Activities:    2008     2007     2006  

Acquisitions of natural gas and oil companies and proved properties, net of cash acquired

   $ 372     $ 520     $ 1,104  

Acquisition of leasehold and unproved properties

     7,660       2,187       3,301  

Exploration and development of natural gas and oil properties

     5,789       4,962       3,009  

Geological and geophysical costs

     315       343       154  

Interest capitalized on unproved properties

     440       254       172  

Proceeds from sale of volumetric production payments

     (1,579 )     (1,089 )      

Deposits for acquisitions

     12       15       21  

Divestitures of proved and unproved properties and leasehold

     (6,091 )            
                        

Total natural gas and oil investing activities

     6,918       7,192       7,761  
                        

Other Investing Activities:

      

Additions to other property and equipment

     3,073       1,439       987  

Proceeds from sale of drilling rigs and equipment

     (64 )     (369 )     (244 )

Proceeds from sale of compressors

     (114 )     (188 )      

Additions to investments

     74       8       554  

Proceeds from sale of investments

     (2 )     (124 )     (159 )

Acquisition of trucking company, net of cash acquired

                 45  

Sale of other assets

     (41 )     (36 )     (2 )
                        

Total other investing activities

     2,926       730       1,181  
                        

Total cash used in investing activities

   $ 9,844     $ 7,922     $ 8,942  
                        

Due to the current financial crisis, decreases in natural gas prices and concerns about an oversupply of natural gas in the U.S. market, we and other exploration and production companies have significantly decreased budgets for natural gas and oil investing activities in 2009. In connection with our reduced budget for acquisitions, we are using our common stock for some or all of the consideration for certain transactions. In December 2008, we registered 25 million shares of common stock that we may offer and issue to acquire assets (including mineral interests), businesses or securities of other companies. As of February 26, 2009, we had issued approximately 16 million shares of common stock for leasehold acquisitions and anticipate we may issue the remaining shares over the course of 2009.

 

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Bank Credit Facilities

We have a $3.5 billion syndicated revolving bank credit facility that matures in November 2012. As of December 31, 2008, we had $3.474 billion in outstanding borrowings under this facility and had utilized approximately $15 million of the facility for various letters of credit. To ensure that our revolving credit facility could be fully utilized in these turbulent economic times, we borrowed the remaining capacity under our facility at the end of the third quarter and invested the cash proceeds in short-term highly liquid securities. As a result, on December 31, 2008, we had cash and cash equivalents on hand of approximately $1.749 billion. All 36 lenders that participate in our revolving credit facility fully funded their commitment, with the exception of Lehman Brothers Commercial Bank, a subsidiary of Lehman Brothers Holdings Inc., which has filed for bankruptcy protection. Lehman Brothers Commercial Bank did not fund its $11 million share of the advance.

Borrowings under the facility are secured by certain producing natural gas and oil properties and bear interest at our option at either (i) the greater of the reference rate of Union Bank of California, N.A., or the federal funds effective rate plus 0.50% or (ii) London Interbank Offered Rate (LIBOR), plus a margin that varies from 0.75% to 1.50% per annum according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are redetermined periodically. The unused portion of the facility is subject to a commitment fee that also varies according to our senior unsecured long-term debt ratings, from 0.125% to 0.30% per annum. Currently the commitment fee is 0.20% per annum. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals. Our subsidiaries, Chesapeake Exploration, L.L.C. and Chesapeake Appalachia, L.L.C., are the borrowers under our revolving bank credit facility and Chesapeake and all its other wholly-owned restricted subsidiaries are guarantors.

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. The credit facility agreement requires us to maintain an indebtedness to total capitalization ratio (as defined) not to exceed 0.70 to 1 and an indebtedness to EBITDA ratio (as defined) not to exceed 3.75 to 1. As defined by the credit facility agreement, our indebtedness to total capitalization ratio was 0.43 to 1 and our indebtedness to EBITDA ratio was 2.43 to 1 at December 31, 2008. 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 $10 million ($50 million in the case of our senior notes issued after 2004), 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 the company and its restricted subsidiaries that we may have with an outstanding principal amount in excess of $75 million.

On October 16, 2008, we closed a new secured revolving bank credit facility for our non-Appalachian midstream operations, which have recently been restructured under a new unrestricted subsidiary, Chesapeake Midstream Partners, L.P. (CMP) and its operating subsidiary, Chesapeake Midstream Operating, L.L.C. (CMO). Twelve financial institutions are in the facility bank group. The facility matures in October 2013, has initial availability of $460 million and may be expanded up to $750 million at CMO’s option, subject to additional bank participation. CMO is utilizing the facility to fund capital expenditures associated with building additional natural gas gathering and other systems associated with our drilling program and for general corporate purposes related to our midstream operations. As of December 31, 2008, we had $460 million in outstanding borrowings under the midstream credit facility.

The midstream credit facility agreement contains various covenants and restrictive provisions which limit the ability of CMP and its subsidiaries to incur additional indebtedness, make investments or loans and create liens. The credit facility agreement requires maintenance of an indebtedness to EBITDA ratio (as defined) not to exceed 3.50 to 1, and an EBITDA (as defined) to interest expense coverage ratio of not less than 2.50 to 1. As defined by the credit facility agreement, our indebtedness to EBITDA ratio was 2.59 to 1 and our EBITDA to interest expense coverage ratio was 9.36 to 1 at December 31, 2008. If CMP or its subsidiaries should fail to perform their obligations under these and other covenants, the revolving credit commitment could be terminated

 

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and any outstanding borrowings under the midstream facility could be declared immediately due and payable. The midstream credit facility agreement also has cross default provisions that apply to other indebtedness CMP and its subsidiaries may have with an outstanding principal amount in excess of $15 million.

Hedging Facilities

We have six secured hedging facilities, each of which permits us to enter into cash-settled natural gas and oil commodity transactions, valued by the counterparty, for up to a stated maximum value. Outstanding transactions under each facility are collateralized by certain of our natural gas and oil properties that do not secure any of our other obligations. The value of reserve collateral pledged to each facility is required to be at least 1.3 or 1.5 times the fair value of transactions outstanding under each facility. In addition, we may pledge collateral from our revolving bank credit facility, from time to time, to these facilities to meet any additional collateral coverage requirements. The hedging facilities are subject to an annual exposure fee, which is assessed quarterly based on the average of the daily negative fair value amounts of the hedges, if any, during the quarter. The hedging facilities contain the standard representations and default provisions that are typical of such agreements. The agreements also contain various restrictive provisions which govern the aggregate natural gas and oil production volumes that we are permitted to hedge under all of our agreements at any one time. The fair value of outstanding transactions, per annum exposure fees and the scheduled maturity dates are shown below.

 

     Secured Hedging Facilities (a)  
     #1     #2     #3     #4     #5     #6  
     ($ in millions)  

Fair value of outstanding transactions, as of December 31, 2008

   $ 116     $ 369     $ 37     $ 9     $ 245     $ 94  

Per annum exposure fee

     1 %     1 %     0.8 %     0.8 %     0.8 %     0.8 %

Scheduled maturity date

     2010       2013       2020       2012       2012       2012  

 

(a) Chesapeake Exploration, L.L.C. is the named party to the facilities numbered 1 – 3 and Chesapeake Energy Corporation is the named party to the facilities numbered 4 – 6.

Our revolving bank credit facility, the midstream credit facility and the secured hedging facilities do not contain material adverse change or adequate assurance covenants. Although the applicable interest rates and commitment fees in our revolving bank credit facility fluctuate slightly based on our long-term senior unsecured credit ratings, neither of our credit facilities nor the secured hedging facilities contain provisions which would trigger an acceleration of amounts due under the facilities or a requirement to post additional collateral in the event of a downgrade of our credit ratings.

 

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Senior Note Obligations

In addition to outstanding revolving bank credit facility borrowings discussed above, as of December 31, 2008, senior notes represented approximately $10.3 billion of our long-term debt and consisted of the following ($ in millions):

 

7.5% Senior Notes due 2013

   $ 364  

7.625% Senior Notes due 2013

     500  

7.0% Senior Notes due 2014

     300  

7.5% Senior Notes due 2014

     300  

7.75% Senior Notes due 2015 (a)

      

6.375% Senior Notes due 2015

     600  

6.625% Senior Notes due 2016

     600  

6.875% Senior Notes due 2016

     670  

6.25% Euro-denominated Senior Notes due 2017 (b)

     835  

6.5% Senior Notes due 2017 (b)

     1,100  

7.25% Senior Notes due 2018

     800  

6.25% Senior Notes due 2018

     600  

6.875% Senior Notes due 2020

     500  

2.75% Contingent Convertible Senior Notes due 2035 (c)

     451  

2.5% Contingent Convertible Senior Notes due 2037 (c)

     1,378  

2.25% Contingent Convertible Senior Notes due 2038 (c)

     1,126  

Discount on senior notes

     (85 )

Interest rate derivatives (d)

     211  
        
   $ 10,250  
        

 

(a) The 7.75% Senior Notes due 2015 were redeemed on July 7, 2008. In connection with the transaction we recorded a $31 million loss (which consisted of a $12 million premium and the write-off of $19 million in various charges associated with the notes).
(b) The principal amount shown is based on the dollar/euro exchange rate of $1.3919 to €1.00 as of December 31, 2008. See Note 10 for information on our related cross currency swap.
(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 2008, 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 2009 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   $ 48.81   May 14, 2016

2.5% due 2037

  May 15, 2017, 2022, 2027, 2032   $ 64.47   November 14, 2017

2.25% due 2038

  December 15, 2018, 2023, 2028, 2033   $ 107.36   June 14, 2019

 

(d) See Note 9 for further discussion related to these instruments.

 

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No scheduled principal payments are required under our senior notes until 2013, when $864 million is due.

As of December 31, 2008 and currently, debt ratings for the senior notes are Ba3 by Moody’s Investor Service (stable outlook), BB by Standard & Poor’s Ratings Services (stable outlook) and BB by Fitch Ratings (negative outlook).

Our senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. We may redeem the senior notes, other than the contingent convertible senior notes, at any time at specified make-whole redemption prices. Senior notes issued before July 2005 are governed by indentures containing covenants that limit our ability and our restricted subsidiaries’ ability to incur additional indebtedness; pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; make investments and other restricted payments; incur liens; enter into sale/leaseback transactions; create restrictions on the payment of dividends or other amounts to us from our restricted subsidiaries; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. Senior notes issued after June 2005 are governed by indentures containing covenants that limit our ability and our restricted subsidiaries’ ability to incur certain secured indebtedness; enter into sale/leaseback transactions; and consolidate, merge or transfer assets. The debt incurrence covenants do not presently restrict our ability to borrow under or expand our secured credit facility. As of December 31, 2008, we estimate that secured commercial bank indebtedness of approximately $5.8 billion could have been incurred under the most restrictive indenture covenant.

Chesapeake Energy Corporation is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. As of December 31, 2007, our obligations under our outstanding senior notes and contingent convertible notes were fully and unconditionally guaranteed, jointly and severally, by all of our wholly-owned subsidiaries, other than minor subsidiaries, on a senior unsecured basis. Since October 2008, following the restructuring of our non-Appalachian midstream operations, certain of our subsidiaries having significant assets and operations have not guaranteed our outstanding senior notes and contingent convertible notes. Condensed consolidating financial information for Chesapeake and its combined guarantor and combined non-guarantor subsidiaries as of and for the year ended December 31, 2008 is provided in Note 16 of the notes to our consolidated financial statements included in Item 8 of this report.

Contractual Obligations

The table below summarizes our contractual obligations as of December 31, 2008 ($ in millions):

 

     Payments Due By Period
     Total    Less than
1 Year
   1-3
Years
   3-5
Years
   More than
5 years

Long term debt:

              

Principal

   $ 14,058    $    $    $ 4,798    $ 9,260

Interest

     6,048      567      1,133      1,133      3,215

Capital lease obligations

     4      3      1          

Operating lease obligations

     946      142      266      270      268

Asset retirement obligations (a)

     269      19      21      6      223

Purchase obligations (b)

     2,349      807      487      320      735

Unrecognized tax benefits (c)

     60           60          

Standby letters of credit

     15      15               
                                  

Total contractual cash obligations

   $ 23,749    $ 1,553    $ 1,968    $ 6,527    $ 13,701
                                  

 

(a) Asset retirement obligations represent estimated discounted costs for future dismantlement and abandonment costs. These obligations are recorded as liabilities on our December 31, 2008 balance sheet.
(b) See Note 4 of the notes to our consolidated financial statements for a description of transportation and drilling contract commitments.
(c) See Note 5 of the notes to our consolidated financial statements for a description of unrecognized tax benefits.

 

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Chesapeake has commitments to purchase natural gas and oil associated with volumetric production payment transactions that extend over terms ranging from 11 to 15 years based on market prices at the time of production and the purchased gas will be resold. The obligations are as follows:

 

     Mmcfe

2009

   68,238

2010

   60,723

2011

   53,694

2012

   48,069

2013

   43,477

After 2013

   181,574
    

Total

   455,775
    

Other Commitments

We own a 49% interest in Mountain Drilling Company, a company that specializes in hydraulic drilling rigs which are designed for drilling in urban areas. Chesapeake has an agreement to lend Mountain Drilling Company up to $32 million through December 31, 2009. At December 31, 2008, Mountain Drilling owed Chesapeake $19 million under this agreement.

We invested in Ventura Refining and Transmission LLC in early 2007 and today own a 25% interest. There were no refineries in western Oklahoma until Ventura opened its refinery in 2006. We have agreed to guarantee various commitments for Ventura, up to $70 million, to support their operating activities. As of December 31, 2008, we had $7 million of outstanding performance guarantees.

Hedging Activities

Natural Gas and Oil Hedging Activities

Our results of operations and operating 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, 2008, our natural gas and oil derivative instruments were comprised of swaps, basis protection swaps, knockout swaps, cap-swaps, call options, put options and collars. Item 7A – Quantitative and Qualitative Disclosures About Market Risk contains a description of each of these instruments. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended.

Hedging allows us to predict with greater certainty the effective prices we will receive for our hedged natural gas and oil production. We closely monitor the fair value of our hedging 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.

 

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Mark-to-market positions under natural gas and oil hedging contracts fluctuate with commodity prices. As described above under Bank Credit Facilities and Hedging Facilities, we may be required to deliver collateral or other assurances of performance if our payment obligations to our hedging counterparties exceed levels stated in our contracts. Our realized and unrealized gains and losses on natural gas and oil derivatives during 2008, 2007 and 2006 were as follows:

 

     Years Ended December 31,
     2008     2007     2006
     ($ in millions)

Natural gas and oil sales

   $ 7,069     $ 4,795     $ 3,870

Realized gains (losses) on natural gas and oil derivatives

     (8 )     1,203       1,254

Unrealized gains (losses) on non-qualifying natural gas and oil derivatives

     887       (252 )     184

Unrealized gains (losses) on ineffectiveness of cash flow hedges

     (90 )     (122 )     311
                      

Total natural gas and oil sales

   $ 7,858     $ 5,624     $ 5,619
                      

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 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 $386 million, $53 million and $546 million as of December 31, 2008, 2007 and 2006, respectively. Based upon the market prices at December 31, 2008, we expect to transfer to earnings approximately $345 million of the net gain included in the balance of accumulated other comprehensive income during the next 12 months. A detailed explanation of accounting for natural gas and oil derivatives under SFAS 133 appears under “Application of Critical Accounting Policies – Hedging” elsewhere in this Item 7.

The estimated fair values of our natural gas and oil derivative instruments as of December 31, 2008 and 2007 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.

 

     December 31,  
         2008             2007      
     ($ in millions)  

Derivative assets (liabilities) (a):

    

Fixed-price natural gas swaps

   $ 863     $ (54 )

Fixed-price natural gas collars

     402       4  

Natural gas basis protection swaps

     93       151  

Fixed-price natural gas knockout swaps

     141       108  

Natural gas call options

     (178 )     (230 )

Natural gas put options

     (39 )      

Fixed-price oil swaps

     31       (110 )

Fixed-price oil knockout swaps

     19       (125 )

Fixed-price oil cap-swaps

     3       (17 )

Oil call options

     (35 )     (96 )

Fixed-price oil collars

     5        
                

Estimated fair value

   $ 1,305     $ (369 )
                

 

(a) See Item 7A. Quantitative and Qualitative Disclosures About Market Risk of this report for additional information concerning any associated premiums received, or discounts paid, in connection with certain derivative transactions.

 

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Additional information concerning the fair value of our natural gas and oil derivative instruments is as follows:

 

     2008     2007     2006  
     ($ in millions)  

Fair value of contracts outstanding, as of January 1

   $ (369 )   $ 345     $ (946 )

Change in fair value of contracts

     1,880       972       3,423  

Fair value of contracts when entered into

     (569 )     (295 )     (32 )

Contracts realized or otherwise settled

     9       (1,203 )     (1,254 )

Fair value of contracts when closed

     354       (188 )     (846 )
                        

Fair value of contracts outstanding, as of December 31

   $ 1,305     $ (369 )   $ 345  
                        

Interest Rate Derivatives

We use interest rate derivatives to mitigate our exposure to the volatility in interest rates. For interest rate derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value are recorded on the consolidated balance sheets as assets (liabilities), and the debt’s carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Changes in the fair value of derivative instruments not qualifying as fair value hedges are recorded currently as adjustments to interest expense.

Gains or losses from derivative transactions are reflected as adjustments to interest expense on the consolidated statements of operations. Realized gains (losses) included in interest expense were $6 million, ($1) million and ($2) million in 2008, 2007 and 2006, respectively. Pursuant to SFAS 133, certain derivatives do not qualify for designation as fair value hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the consolidated statements of operations as unrealized gains (losses) within interest expense. Unrealized gains (losses) included in interest expense were ($85) million, ($40) million and $2 million in 2008, 2007 and 2006, respectively. A detailed explanation of accounting for interest rate derivatives under SFAS 133 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 a cross currency swap to mitigate our exposure to fluctuations in the euro relative to the dollar over the term of the notes. A detailed explanation of accounting for foreign currency derivatives under SFAS 133 appears under “Application of Critical Accounting Policies – Hedging” elsewhere in this Item 7.

Results of Operations

General.    For the year ended December 31, 2008, Chesapeake had net income of $723 million, or $1.14 per diluted common share, on total revenues of $11.629 billion. This compares to net income of $1.451 billion, or $2.62 per diluted common share, on total revenues of $7.800 billion during the year ended December 31, 2007, and net income of $2.003 billion, or $4.35 per diluted common share, on total revenues of $7.326 billion during the year ended December 31, 2006.

Natural Gas and Oil Sales.    During 2008, natural gas and oil sales were $7.858 billion compared to $5.624 billion in 2007 and $5.619 billion in 2006. In 2008, Chesapeake produced and sold 842.7 bcfe of natural gas and oil at a weighted average price of $8.38 per mcfe, compared to 714.3 bcfe in 2007 at a weighted average price of $8.40 per mcfe, and 578.4 bcfe in 2006 at a weighted average price of $8.86 per mcfe (weighted average prices

 

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for all years discussed exclude the effect of unrealized gains or (losses) on derivatives of $797 million, ($374) million and $495 million in 2008, 2007 and 2006, respectively). The decrease in prices in 2008 resulted in a decrease in revenue of $17 million and increased production resulted in a $1.079 billion increase, for a total increase in revenues of $1.062 billion (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 2008, we realized an average price per mcf of natural gas of $8.09, compared to $8.14 in 2007 and $8.76 in 2006 (weighted average prices for all years discussed exclude the effect of unrealized gains or losses on derivatives). Oil prices realized per barrel (excluding unrealized gains or losses on derivatives) were $70.48, $67.50 and $59.14 in 2008, 2007 and 2006, respectively. Realized gains or losses from our natural gas and oil derivatives resulted in a net decrease in natural gas and oil revenues of ($9) million or ($0.01) per mcfe in 2008, a net increase of $1.203 billion or $1.68 per mcfe in 2007 and a net increase of $1.254 billion or $2.17 per mcfe in 2006.

A change in natural gas and oil prices has a significant impact on our natural gas and oil revenues and cash flows. Assuming 2008 production levels, a change of $0.10 per mcf of natural gas sold would result in an increase or decrease in 2008 revenues and cash flows of approximately $78 million and $75 million, respectively, and a change of $1.00 per barrel of oil sold would result in an increase or decrease in 2008 revenues and cash flows of approximately $11 million without considering the effect of hedging activities.

The following table shows our production by region for 2008, 2007 and 2006:

 

     Years Ended December 31,  
     2008     2007     2006  
     Mmcfe    Percent     Mmcfe    Percent     Mmcfe    Percent  

Mid-Continent (a) (b)

   412,825    49 %   373,941    52 %   315,173    55 %

Barnett Shale

   181,523    22     93,463    13     44,482    7  

Permian and Delaware Basins

   79,645    10     64,897    9     48,510    8  

South Texas and Texas Gulf Coast

   70,903    8     78,228    11     79,178    14  

Ark-La-Tex

   61,543    7     55,811    8     46,009    8  

Appalachian Basin (c)

   36,305    4     47,922    7     45,031    8  
                                 

Total Production

   842,744    100 %   714,262    100 %   578,383    100 %
                                 

 

(a) 2008 was impacted by the sale of 11.1 bcf and 6.9 bcf of production in VPP transactions that closed on May 1, 2008 and August 1, 2008, respectively.
(b) 2008 was impacted by the sale of 7.6 bcf and 4.7 bcf of production from Arkoma and Fayetteville properties, respectively.
(c) 2008 was impacted by the sale of 18.3 bcf of production in a VPP transaction that closed on December 31, 2007.

Natural gas production represented approximately 92% of our total production volume on a natural gas equivalent basis in 2008, compared to 92% in 2007 and 91% in 2006.

Natural Gas and Oil Marketing Sales and Operating Expenses.    Natural gas and oil marketing activities are substantially for third parties who are owners in Chesapeake-operated wells. Chesapeake realized $3.598 billion in natural gas and oil marketing sales to third parties in 2008, with corresponding natural gas and oil marketing expenses of $3.505 billion, for a net margin before depreciation of $93 million. This compares to sales of $2.040 billion and $1.577 billion, expenses of $1.969 billion and $1.522 billion, and margins before depreciation of $71 million and $55 million in 2007 and 2006, respectively. The net margin increase in 2008 and 2007 is primarily due to an increase in volumes related to natural gas and oil marketing sales.

Service Operations Revenue and Operating Expenses.    Service operations consist of third-party revenue and operating expenses related to our drilling and oilfield trucking operations. Chesapeake recognized $173 million in service operations revenue in 2008 with corresponding service operations expenses of $143 million,

 

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for a net margin before depreciation of $30 million. This compares to revenue of $136 million and $130 million, expenses of $94 million and $68 million and a net margin before depreciation of $42 million and $62 million in 2007 and 2006, respectively. These operations have grown as a result of assets and businesses we acquired and leased as seen in the growth in revenues. However, the net margins have decreased each of the previous three years. This is the result of increased expenses associated with the leasing cost of the numerous rigs we have sold and leased back in the previous three years.

Production Expenses.    Production expenses, which include lifting costs and ad valorem taxes, were $889 million in 2008, compared to $640 million and $490 million in 2007 and 2006, respectively. On a unit-of-production basis, production expenses were $1.05 per mcfe in 2008 compared to $0.90 and $0.85 per mcfe in 2007 and 2006, respectively. The expense increase in 2008 was primarily due to higher third-party field service costs, energy costs, fuel costs, ad valorem taxes and personnel costs. Our per unit increase in 2008 was also affected by the loss of production related to the sale of the volumetric production payments. We expect that production expenses per mcfe produced for 2009 will range from $1.10 to $1.20.

Production Taxes.    Production taxes were $284 million in 2008 compared to $216 million in 2007 and $176 million in 2006. On a unit-of-production basis, production taxes were $0.34 per mcfe in 2008 compared to $0.30 per mcfe in 2007 and $0.31 per mcfe in 2006. The $68 million increase in production taxes from 2007 to 2008 is due to an increase in production of 128 bcfe and an increase in the realized average sales price of natural gas and oil of $1.68 per mcfe (excluding gains or losses on derivatives).

In general, production taxes are calculated using value-based formulas that produce higher per unit costs when natural gas and oil prices are higher. We expect production taxes for 2009 to range from $0.25 to $0.35 per mcfe based on estimated NYMEX prices ranging from $6.00 to $7.50 per mcf of natural gas and an oil price of $47.66 per barrel.

General and Administrative Expense.    General and administrative expenses, including stock-based compensation but excluding internal costs capitalized to our natural gas and oil properties (see Note 10 of notes to consolidated financial statements), were $377 million in 2008, $243 million in 2007 and $139 million in 2006. General and administrative expenses were $0.45, $0.34 and $0.24 per mcfe for 2008, 2007 and 2006, respectively. The increase in 2008, 2007 and 2006 was the result of increasing labor costs due to the company’s continued growth as well as increased media and advocacy expenditures. Included in general and administrative expenses is stock-based compensation of $85 million in 2008, $58 million in 2007 and $27 million in 2006. The increase was mainly due to an increase in the number of unvested restricted shares outstanding during 2008 compared to 2007 and 2006 as a result of growth in our employment. We anticipate that general and administrative expenses for 2009 will be between $0.33 and $0.37 per mcfe produced, including stock-based compensation ranging from $0.10 to $0.12 per mcfe produced.

Our stock-based compensation for employees and non-employee directors is in the form of restricted stock. Employee restricted stock awards generally vest over a period of four or five years. Our non-employee director awards vest over a period of three years. The discussion of stock-based compensation in Note 1 and Note 8 of notes to the consolidated financial statements included in Item 8 of this report provides additional detail on the accounting for and reporting of our stock-based compensation.

Chesapeake follows the full-cost method of accounting under which all costs associated with natural gas and oil property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. We capitalized $352 million, $262 million and $161 million of internal costs in 2008, 2007 and 2006, respectively, directly related to our natural gas and oil property acquisition, exploration and development efforts.

Natural Gas and Oil Depreciation, Depletion and Amortization.    Depreciation, depletion and amortization of natural gas and oil properties was $1.970 billion, $1.835 billion and $1.359 billion during 2008, 2007 and

 

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2006, respectively. The average DD&A rate per mcfe, which is a function of capitalized costs, future development costs, and the related underlying reserves in the periods presented, was $2.34, $2.57 and $2.35 in 2008, 2007 and 2006, respectively. The decrease in the average rate from $2.57 in 2007 to $2.34 in 2008 is due primarily to the reduction of our natural gas and oil full-cost pool resulting from our divestitures in 2008 and the addition of reserves through our exploration activities. We expect the 2009 DD&A rate to be between $1.90 and $2.00 per mcfe produced.

Depreciation and Amortization of Other Assets.    Depreciation and amortization of other assets was $177 million in 2008, compared to $154 million in 2007 and $104 million in 2006. The average D&A rate per mcfe was $0.21, $0.22 and $0.18 in 2008, 2007 and 2006, respectively. Property and equipment costs are depreciated on a straight-line basis. Buildings are depreciated over 15 to 39 years, gathering facilities are depreciated over 20 years, drilling rigs are depreciated over 15 years and all other property and equipment are depreciated over the estimated useful lives of the assets, which range from two to ten years. To the extent company-owned drilling rigs are used to drill our wells, a substantial portion of the depreciation is capitalized in natural gas and oil properties as exploration or development costs. We expect 2009 depreciation and amortization of other assets to be between $0.24 and $0.28 per mcfe produced.

Impairment of Natural Gas and Oil Properties and Other Fixed Assets.    Due to lower commodity prices at December 31, 2008, we reported a non-cash impairment charge of $2.8 billion for 2008. We account for our natural gas and oil properties using the full-cost method of accounting, which limits the amount of costs we can capitalize and requires us to write off these costs if the carrying value of natural gas and oil assets in the evaluated portion of our full-cost pool exceeds the sum of the present value of expected future net cash flows of proved reserves using a 10% pre-tax discount rate based on constant pricing and cost assumptions and the present value of certain natural gas and oil hedges. Additionally in 2008, we recorded an impairment of $30 million associated with certain of our midstream assets.

Employee Retirement Expense.    Our President and Chief Operating Officer, Tom L. Ward, resigned as a director, officer and employee of the company effective February 10, 2006. Mr. Ward’s Resignation Agreement provided for the immediate vesting of all of his unvested equity awards, which consisted of options to purchase 724,615 shares of Chesapeake’s common stock at an average exercise price of $8.01 per share and 1,291,875 shares of restricted common stock. As a result of this vesting, we incurred an expense of $55 million in 2006.

Interest and Other Income.    Interest and other income was ($11) million, $15 million and $26 million in 2008, 2007 and 2006, respectively. The 2008 loss consisted of $22 million of interest income, a $38 million loss related to our equity in the net losses of certain investments, a $4 million gain on sale of assets, $10 million of expense related to consent solicitation fees and $11 million of miscellaneous income. The 2007 income consisted of $8 million of interest income and $7 million of miscellaneous income. Income related to equity investments was not significant in 2007. The 2006 income consisted of $5 million of interest income, $10 million of income related to equity investments, a $5 million gain on sale of assets and $6 million of miscellaneous income.

Interest Expense.    Interest expense decreased to $314 million in 2008 compared to $406 million in 2007 and $301 million in 2006 as follows:

 

     Years Ended December 31,  
     2008     2007     2006  
     ($ in millions)  

Interest expense on senior notes and revolving bank credit facility

   $ 687     $ 616     $ 472  

Capitalized interest

     (464 )     (269 )     (179 )

Amortization of loan discount and other

     12       17       7  

Unrealized (gain) loss on interest rate derivatives

     85       41       (1 )

Realized (gain) loss on interest rate derivatives

     (6 )     1       2  
                        

Total interest expense

   $ 314     $ 406     $ 301  
                        

Average long-term borrowings

   $ 10,044     $ 8,224     $ 6,278  
                        

 

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Interest expense, excluding unrealized (gains) losses on interest rate derivatives was $0.27 per mcfe in 2008 compared to $0.51 per mcfe in 2007 and $0.52 per mcfe in 2006. The decrease in interest expense per mcfe for 2008 is due to increased production volumes and an increase in capitalized interest. Capitalized interest increased in 2008 and 2007 as a result of a significant increase in unevaluated properties, the base on which interest is capitalized. We expect interest expense for 2009 to be between $0.30 and $0.35 per mcfe produced (before considering the effect of interest rate derivatives).

Gain on Exchanges or Repurchases of Chesapeake Debt.    In 2008, we redeemed $300 million of our 7.75% Senior Notes due 2015 with proceeds from the issuance of new senior notes with a lower rate of interest. In connection with the redemption, we recorded a $31 million loss (which consisted of a $12 million premium and the write-off of $19 million in various charges associated with the notes). Also in 2008, we privately exchanged approximately $765 million in aggregate principal amount of our 2.75% Contingent Convertible Senior Notes due 2035, our 2.50% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038 for an aggregate of 23,913,203 shares of our common stock. The difference between the face value of the notes that were exchanged and the fair value of the common stock issued resulted in a gain of $268 million on the cancellation of indebtedness.

Impairment of Investments.    In 2008, we recorded a $180 million impairment of certain investments. Each of our investees has been impacted by the dramatic slowing of the worldwide economy and the freezing of the credit markets in the fourth quarter of 2008 and into 2009. The economic weakness has resulted in significantly reduced natural gas and oil prices leading to a meaningful decline in the overall level of activity in the markets served by our investees. Associated with the weakness in performance of certain of the investees, as well as an evaluation of their financial condition and near-term prospects, we recognized that an other than temporary impairment had occurred on the following investments: Chaparral Energy, Inc., $100 million; DHS Drilling Company, $20 million; Mountain Drilling Company, $10 million; and Ventura Refining and Transmission LLC, Inc., $50 million.

Gain on Sale of Investments.    In 2007, we sold our 33% limited partnership interest in Eagle Energy Partners I, L.P., which we first acquired in 2003, for proceeds of $124 million and a gain of $83 million. In 2006, Chesapeake sold its investment in publicly-traded Pioneer Drilling Company common stock, realizing proceeds of $159 million and a gain of $117 million. At the time of sale, we owned 17% of the common stock of Pioneer, which we began acquiring in 2003.

Income Tax Expense.    Chesapeake recorded income tax expense of $463 million in 2008 compared to income tax expense of $890 million in 2007 and $1.252 billion in 2006. Of the income tax expense recorded in 2008, $423 million is reflected as current income tax expense and $40 million is reflected as deferred income tax expense. The divestitures that closed during 2008 are projected to generate sufficient taxable income for the year to exhaust all our non-limited NOLs and result in a current tax liability for the tax year ended December 31, 2008. Of the $427 million decrease in 2008, $439 million was the result of the decrease in net income before taxes which was offset by $12 million as the result of an increase in the effective tax rate. Our effective income tax rate was 39% in 2008 compared to 38% in 2007 and 38.5% in 2006. Our effective tax rate fluctuates as a result of the impact of state income taxes and permanent differences. We expect our effective income tax rate to be 39% in 2009.

Loss on Conversion/Exchange of Preferred Stock.    Loss on conversion/exchange of preferred stock was $67 million, $128 million and $10 million in 2008, 2007 and 2006, respectively. The loss on the exchanges represented the excess of the fair value of the common stock issued over the fair value of the securities issuable pursuant to the original conversion terms. See Note 8 of notes to the consolidated financial statements in Item 8 for further detail regarding these transactions.

Application of Critical Accounting Policies

Readers of this report and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. The four policies we consider to be

 

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the most significant are discussed below. The company’s management has discussed each critical accounting policy with the Audit Committee of the company’s Board of Directors.

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

Hedging.    Chesapeake uses commodity price and financial risk management instruments to mitigate our exposure to price fluctuations in natural gas and oil, changes in interest rates and changes in foreign exchange rates. Recognized gains and losses on derivative contracts are reported as a component of the related transaction. Results of natural gas and oil derivative transactions are reflected in natural gas and oil sales, and results of interest rate and foreign exchange rate hedging transactions are reflected in interest expense. The changes in the fair value of derivative instruments not qualifying for designation as either cash flow or fair value hedges that occur prior to maturity are reported currently in the consolidated statement of operations as unrealized gains (losses) within natural gas and oil sales or interest expense. Cash flows from derivative instruments are classified in the same category within the statement of cash flows as the items being hedged, or on a basis consistent with the nature of the instruments.

Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in the fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in natural gas and oil sales. For derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent gains or losses on ineffectiveness and are reflected currently in interest expense. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are also recognized currently in earnings. See “Hedging Activities” above and Item 7A – Quantitative and Qualitative Disclosures About Market Risk for additional information regarding our hedging activities.

One of the primary factors that can have an impact on our results of operations is the method used to value our derivatives. We have established the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors.

Another factor that can impact our results of operations each period is our ability to estimate the level of correlation between future changes in the fair value of the hedge instruments and the transactions being hedged, both at inception and on an ongoing basis. This correlation is complicated since energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control.

 

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Due to the volatility of natural gas and oil prices and, to a lesser extent, interest rates and foreign exchange rates, the company’s financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2008, 2007 and 2006, the net market value of our derivatives was an asset of $1.305 billion, a liability of $375 million and an asset of $293 million, respectively. The derivatives that we acquired in our CNR acquisition represented $17 million, $184 million and $254 million of liability at December 31, 2008, 2007 and 2006.

Natural Gas and Oil Properties.    The accounting for our business is subject to special accounting rules that are unique to the natural gas and oil industry. There are two allowable methods of accounting for natural gas and oil business activities: the successful efforts method and the full-cost method. Chesapeake follows the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities.

Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of natural gas and oil properties are generally calculated on a well by well or lease or field basis versus the aggregated “full-cost” pool basis. Additionally, gain or loss is generally recognized on all sales of natural gas and oil properties under the successful efforts method. As a result, our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher natural gas and oil depreciation, depletion and amortization rate, and we will not have exploration expenses that successful efforts companies frequently have.

Under the full-cost method, capitalized costs are amortized on a composite unit-of-production method based on proved natural gas and oil reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves changes significantly. Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred. Unevaluated properties are grouped by major producing area where individual property costs are not significant and are assessed individually when individual costs are significant.

We review the carrying value of our natural gas and oil properties under the full-cost accounting rules of the Securities and Exchange Commission on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. As of December 31, 2008, capitalized costs of natural gas and oil properties exceeded the estimated present value of future net revenues from our proved reserves, net of related income tax considerations, resulting in a write-down in the carrying value of natural gas and oil properties of $2.8 billion. In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. Based on spot prices for natural gas and oil as of December 31, 2008, these cash flow hedges increased the full-cost ceiling by $1.024 billion, thereby reducing the ceiling test write-down by the same amount.

Two primary factors impacting this test are reserve levels and current prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues.

 

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Any excess of the net book value, less deferred income taxes, is generally written off as an expense. Under SEC regulations, the excess above the ceiling is not expensed (or is reduced) if, subsequent to the end of the period, but prior to the release of the financial statements, natural gas and oil prices increase sufficiently such that an excess above the ceiling would have been eliminated (or reduced) if the increased prices were used in the calculations.

The process of estimating natural gas and oil reserves is very complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates.

Our internal petroleum reservoir engineers evaluated and estimated all of our proved reserves as of December 31, 2008, and independent petroleum engineers audited approximately 76% of our estimated proved reserves (by volume). In addition, our internal engineers review and update our reserves on a quarterly basis. All reserve estimates are prepared based upon a review of production histories and other geologic, economic, ownership and engineering data we developed. Additional information about our 2008 year-end reserve evaluation is included under “Natural Gas and Oil Reserves” in Item 1 – Business.

Income Taxes.    As part of the process of preparing the consolidated financial statements, we are required to estimate the federal and state income taxes in each of the jurisdictions in which Chesapeake operates. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as derivative instruments, depreciation, depletion and amortization, and certain accrued liabilities for tax and accounting purposes. These differences and our net operating loss carryforwards result in deferred tax assets and liabilities, which are included in our consolidated balance sheet. We must then assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. If we believe that recovery is not likely, we must establish a valuation allowance. Generally, to the extent Chesapeake establishes a valuation allowance or increases or decreases this allowance in a period, we must include an expense or reduction of expense within the tax provision in the consolidated statement of operations.

Under Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, an enterprise must use judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified. The more negative evidence that exists (a) the more positive evidence is necessary and (b) the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion or all of the deferred tax asset. Among the more significant types of evidence that we consider are:

 

   

taxable income projections in future years,

 

   

whether the carryforward period is so brief that it would limit realization of tax benefits,

 

   

future sales and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures, and

 

   

our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition.

If (a) natural gas and oil prices were to decrease significantly below present levels (and if such decreases were considered other than temporary), (b) exploration, drilling and operating costs were to increase significantly beyond current levels, or (c) we were confronted with any other significantly negative evidence pertaining to our

 

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ability to realize our NOL carryforwards prior to their expiration, we may be required to provide a valuation allowance against our deferred tax assets. As of December 31, 2008, we had deferred tax assets of $347 million.

FASB Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109, provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. Based on this guidance, we regularly analyze tax positions taken or expected to be taken in a tax return based on the threshold condition prescribed under FIN 48. Tax positions that do not meet or exceed this threshold condition are considered uncertain tax positions. We accrue interest related to these uncertain tax positions which is recognized in interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. Additional information about uncertain tax positions appears in “Income Taxes” in Item 1 – Business.

Accounting for Business Combinations.    Our business has grown substantially through acquisitions and our business strategy is to continue to pursue acquisitions as opportunities arise. We have accounted for all of our business combinations using the purchase method, which is the only method permitted under SFAS 141, Accounting for Business Combinations. The accounting for business combinations is complicated and involves the use of significant judgment.

Under the purchase method of accounting, a business combination is accounted for at its purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, stock or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the cost of an acquired entity, if any, over the net of the amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain acquired assets.

Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and liabilities acquired do not have fair values that are readily determinable. Different techniques may be used to determine fair values, including market prices, where available, appraisals, comparisons to transactions for similar assets and liabilities and present value of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.

We believe that the consideration we have paid for our natural gas and oil property acquisitions has represented the fair value of the assets and liabilities acquired at the time of purchase. Consequently, we have not recognized any goodwill from any of our natural gas and oil property acquisitions, nor do we expect to recognize goodwill from similar business combinations that we may complete in the future.

Disclosures About Effects of Transactions with Related Parties

Since Chesapeake was founded in 1989, our CEO, Aubrey K. McClendon, has acquired working interests in virtually all of our natural gas and oil properties by participating in our drilling activities under the terms of the Founder Well Participation Program (“FWPP”) and predecessor participation arrangements provided for in Mr. McClendon’s employment agreements. Under the FWPP, approved by our shareholders in June 2005, Mr. McClendon may elect to participate in all or none of the wells drilled by or on behalf of Chesapeake during a calendar year, but he is not allowed to participate only in selected wells. A participation election is required to be received by the Compensation Committee of Chesapeake’s Board of Directors not less than 30 days prior to the start of each calendar year. His participation is permitted only under the terms outlined in the FWPP, which, among other things, limits his individual participation to a maximum working interest of 2.5% in a well and prohibits participation in situations where Chesapeake’s working interest would be reduced below 12.5% as a result of his participation. In addition, the company is reimbursed for costs associated with leasehold acquired by Mr. McClendon as a result of his well participation.

 

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On December 31, 2008, we entered into a new five-year employment agreement with Mr. McClendon that contained a one-time well cost incentive award to him. The total cost of the award to Chesapeake was $75 million plus employment taxes in the amount of approximately $1 million. We will recognize the incentive award as general and administrative expense over the five-year vesting period for the clawback described below, resulting in an expense of approximately $15 million per year beginning in 2009. In addition to state and federal income tax withholding, similar employment taxes were imposed on Mr. McClendon and withheld from the award. The net incentive award of approximately $44 million can only be applied against costs attributable to interests in company wells acquired by Mr. McClendon or his affiliates under the FWPP. The incentive award is subject to a clawback if, during the initial five-year term of the employment agreement, Mr. McClendon resigns from the company or is terminated for cause by the company. Upon receipt of the company’s monthly invoice for joint interest billings in mid-January 2009, Mr. McClendon elected to apply approximately $19 million of the drilling credit against his December 2008 FWPP joint interest billings, leaving $25 million available as a credit against future billings. Based on our current development plans and Mr. McClendon’s election under the FWPP to participate with a 2.5% working interest during 2009, the well costs under the FWPP are expected to exceed the amount of the entire FWPP credit in early 2009. We refer you to the discussion of the FWPP and Mr. McClendon’s employment agreement contained in our proxy statement for our 2009 annual meeting of shareholders, which discussion is incorporated by reference in Part III of this report.

As disclosed in Note 14, in 2008, Chesapeake had revenues of $1.3 billion from natural gas and oil sales to Eagle Energy Partners I, L.P., a former affiliated entity. We sold our 33% limited partnership interest in Eagle Energy in June 2007.

Recently Issued Accounting Standards

The FASB recently issued the following standards which were reviewed by Chesapeake to determine the potential impact on our financial statements upon adoption.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of Accounting Research Bulletin No. 51. This statement requires an entity to separately disclose non-controlling interests as a separate component of equity in the balance sheet and clearly identify on the face of the income statement net income related to non-controlling interests. This statement is effective for financial statements issued for fiscal years beginning after December 15, 2008. The adoption of this statement will not have a material impact on our financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141 (R), Business Combinations. This statement requires assets acquired and liabilities assumed to be measured at fair value as of the acquisition date, acquisition-related costs incurred prior to the acquisition to be expensed and contractual contingencies to be recognized at fair value as of the acquisition date. This statement is effective for financial statements issued for fiscal years beginning after December 15, 2008. We will comply with this statement prospectively in accounting for future business combinations.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133. This statement changes the disclosure requirements for derivative instruments and hedging activities. The statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. This statement will not have a material impact on our financial disclosures.

In May 2008, the FASB issued FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement). FSP APB 14-1 clarifies that convertible debt instruments that may be settled in cash upon either mandatory or optional conversion (including partial cash settlement) are not addressed by paragraph 12 of APB Opinion No. 14, Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants. The accounting prescribed by FSP APB 14-1 increases the amount of

 

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interest expense required to be recognized with respect to such instruments and, thus, lowers reported net income and net income per share of issuers of such instruments. Issuers must account for the liability and equity components of the instrument separately and in a manner that reflects interest expense at the interest rate of similar nonconvertible debt. We have three debt series that will be affected by the guidance, 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. This staff position is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008 and must be applied on a retrospective basis. The initial adoption of FSP APB 14-1 is expected to decrease the carrying value of our Contingent Convertible Senior Notes by approximately $1 billion, increase shareholders’ equity by approximately $600 million and increase deferred tax liabilities by approximately $400 million. In addition, we currently estimate that we will record additional non-cash interest expense, which will reduce our pre-tax income by approximately $80 million and reduce net income by approximately $50 million for the year ended December 31, 2009.

In June 2008, the FASB issued FSP Emerging Issues Task Force (EITF) No. 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. FSP EITF 03-6-1 addresses whether instruments granted in share-based payments transactions are participating securities prior to vesting and therefore need to be included in the earnings allocation in calculating earnings per share under the two-class method described in SFAS No. 128, Earnings per Share. FSP EITF No. 03-6-1 requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividend or dividend equivalents as a separate class of securities in calculating earnings per share. FSP EITF No. 03-6-1 is effective for fiscal years beginning after December 15, 2008; earlier application is not permitted. FSP EITF No. 03-6-1 could be applicable to us but we have no current transactions that would be affected.

In October 2008, the FASB issued FSP FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active. FSP FAS 157-3 clarifies the application of FASB statement No. 157, Fair Value Measurements, in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. This FSP could be applicable to us but we currently have no financial assets of this type.

On December 31, 2008, the Securities and Exchange Commission (SEC) adopted major revisions to its rules governing oil and gas company reporting requirements. These include provisions that permit the use of new technologies to determine proved reserves and that allow companies to disclose their probable and possible reserves to investors. The current rules limit disclosure to only proved reserves. The new disclosure requirements also require companies to report the independence and qualifications of the person primarily responsible for the preparation or audit of reserve estimates, and to file reports when a third party is relied upon to prepare or audit reserves estimates. The new rules also require that oil and gas reserves be reported and the full-cost ceiling value calculated using an average price based upon the prior 12-month period. The new oil and gas reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, with early adoption not permitted. We are in the process of assessing the impact of these new requirements on our financial position, results of operations and financial disclosures.

Forward-Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include estimates of natural gas and oil reserves, expected natural gas and oil production and future expenses, assumptions regarding future natural gas and oil prices, planned capital expenditures, and anticipated asset acquisitions and sales, as well as statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures concerning the fair values of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility.

 

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Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results are described under “Risk Factors” in Item 1A of this report and include:

 

   

the volatility of natural gas and oil prices,

 

   

the limitations our level of indebtedness may have on our financial flexibility,

 

   

impacts the current financial crisis may have on our business and financial condition,

 

   

declines in the values of our natural gas and oil properties resulting in ceiling test write-downs,

 

   

the availability of capital on an economic basis, including planned asset monetization transactions, to fund reserve replacement costs,

 

   

our ability to replace reserves and sustain production,

 

   

uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and the timing of development expenditures,

 

   

exploration and development drilling that does not result in commercially productive reserves,

 

   

leasehold terms expiring before production can be established,

 

   

hedging activities resulting in lower prices realized on natural gas and oil sales and the need to secure hedging liabilities,

 

   

uncertainties in evaluating natural gas and oil reserves of acquired properties and potential liabilities,

 

   

the negative effect lower natural gas and oil prices could have on our ability to borrow,

 

   

drilling and operating risks, including potential environmental liabilities,

 

   

transportation capacity constraints and interruptions that could adversely affect our cash flow,

 

   

adverse effects of governmental and environmental regulation, and

 

   

losses possible from pending or future litigation.

We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this report, and we undertake no obligation to update this information. We urge you to carefully review and consider the disclosures made in this report and our other filings with the Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect our business.

 

ITEM 7A.    Quantitative and Qualitative Disclosures About Market Risk

Natural Gas and Oil Hedging Activities

Our results of operations and operating 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. As of December 31, 2008, our natural gas and oil derivative instruments were comprised of swaps, basis protection swaps, knockout swaps, cap-swaps, call options, put options and collars. These instruments allow us to predict with greater certainty the effective natural gas and oil prices to be received for our hedged production. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended.

 

   

For swap instruments, Chesapeake receives a fixed price for the hedged commodity and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

 

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Basis protection swaps are arrangements that guarantee a price differential for natural gas or oil from a specified delivery point. For Mid-Continent basis protection swaps, which typically have negative differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. For Appalachian Basin basis protection swaps, which typically have positive differentials to NYMEX, Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.

 

   

For knockout swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for the possibility to reduce the counterparty’s exposure to zero, in any given month, if the floating market price is lower than certain pre-determined knockout prices.

 

   

For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a “cap” limiting the counterparty’s exposure. In other words, there is no limit to Chesapeake’s exposure but there is a limit to the downside exposure of the counterparty.

 

   

For call options, Chesapeake receives a premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake.

 

   

For put options, Chesapeake receives a premium from the counterparty in exchange for the sale of a put option. If the market price falls below the fixed price of the put option, Chesapeake pays the counterparty such shortfall. If the market price settles above the fixed price of the put option, no payment is due from Chesapeake.

 

   

Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.

Chesapeake enters into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, Chesapeake receives a floating price for the hedged commodity and pays a fixed price to the counterparty. The counter-swap is 100% effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap. We refer to this locked-in value as a locked swap. Generally, at the time Chesapeake enters into a counter-swap, Chesapeake removes the original swap’s designation as a cash flow hedge and classifies the original swap as a non-qualifying hedge under SFAS 133. The reason for this new designation is that collectively the swap and the counter-swap no longer hedge the exposure to variability in expected future cash flows. Instead, the swap and counter-swap effectively lock-in a specific gain or loss that will be unaffected by subsequent variability in natural gas and oil prices. Any locked-in gain or loss is recorded in accumulated other comprehensive income and reclassified to natural gas and oil sales in the month of related production.

In accordance with FASB Interpretation No. 39, to the extent that a legal right of set-off exists, Chesapeake nets the value of its derivative arrangements with the same counterparty in the accompanying consolidated balance sheets.

Gains or losses from certain derivative transactions are reflected as adjustments to natural gas and oil sales on the consolidated statements of operations. Realized gains (losses) are included in natural gas and oil sales in the month of related production. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the consolidated statements of operations as unrealized gains (losses) within natural gas and oil sales. Following provisions of SFAS 133, changes in the fair value of

 

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derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in natural gas and oil sales as unrealized gains (losses). The components of natural gas and oil sales for the years ended December 31, 2008, 2007 and 2006 are presented below.

 

     Years Ended December 31,
     2008     2007     2006
     ($ in millions)

Natural gas and oil sales

   $ 7,069     $ 4,795     $ 3,870

Realized gains (losses) on natural gas and oil derivatives

     (8 )     1,203       1,254

Unrealized gains (losses) on non-qualifying natural gas and oil derivatives

     887       (252 )     184

Unrealized gains (losses) on ineffectiveness of cash flow hedges

     (90 )     (122 )     311
                      

Total natural gas and oil sales

   $ 7,858     $ 5,624     $ 5,619
                      

As of December 31, 2008, we had the following open natural gas and oil derivative instruments (including derivatives assumed through our acquisition of CNR in November 2005) designed to hedge a portion of our natural gas and oil production for periods after December 2008:

 

    Volume   Weighted
Average
Fixed
Price to be
Received
  Weighted
Average
Put
Fixed
Price
  Weighted
Average
Call
Fixed
Price
  Weighted
Average
Differential
    SFAS 133
Hedge
  Net
Premiums
($ in millions)
    Fair
Value at
December 31,
2008

($ in millions)
 

Natural Gas (bbtu):

               

Swaps:

               

Q1 2009

  81,760   $ 8.17   $   $   $     Yes   $     $ 169  

Q2 2009

  57,518     8.39                 Yes           148  

Q3 2009

  59,114     8.47                 Yes           138  

Q4 2009

  72,584     8.42                 Yes           121  

2010

  98,249     9.74                 Yes           250  

2011

  23,725     8.51                 Yes           27  

Collars:

               

Q1 2009

  14,580         7.63     8.98         Yes           28  

Q2 2009

  17,290         7.50     8.36         Yes           31  

Q3 2009

  20,520         7.50     8.35         Yes           31  

Q4 2009

  16,290         7.50     8.35         Yes           17  

Knockout Swaps:

               

Q1 2009

  9,150     10.09     6.03             No     5       6  

Q2 2009

  2,730     8.52     6.00             No     6       1  

Q3 2009

  2,760     8.64     6.00             No     6       1  

Q4 2009

  39,970     9.79     6.30             No     6       14  

2010

  321,150     9.78     6.23             No     1       106  

2011

  138,600     9.74     6.31             No           16  

2012

  18,300     9.60     6.50             No           (3 )

Basis Protection Swaps (Mid-Continent):

               

Q1 2009

  26,873                 (0.47 )   No           25  

Q2 2009

  16,457                 (0.27 )   No           18  

Q3 2009

  16,821                 (0.27 )   No           11  

Q4 2009

  16,953                 (0.27 )   No           13  

2011

  45,090                 (0.64 )   No     (3 )     14  

2012 – 2018

  57,961                 (0.62 )   No     (3 )     10  

Basis Protection Swaps (Appalachian Basin):

               

2009

  16,913                 0.28     No            

2010

  10,199                 0.26     No           1  

2011

  12,086                 0.25     No           1  

2012 – 2022

  134                 0.11     No            

Other Swaps (a):

               

Q1 2009

  4,500     10.14                 No           19  

Q2 2009

  4,550     9.86                 No           5  

Q3 2009

  4,600     9.94                 No           5  

Q4 2009

  4,600     10.24                 No           7  

2010

  32,850     9.89                 No           (7 )

2011

  4,500     8.73                 No           (2 )

 

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    Volume     Weighted
Average
Fixed
Price to be
Received
  Weighted
Average
Put Fixed
Price
  Weighted
Average
Call
Fixed
Price
  Weighted
Average
Differential
  SFAS 133
Hedge
  Net
Premiums
($ in millions)
    Fair
Value at
December 31,
2008

($ in millions)
 

Call Options:

               

Q1 2009

  20,355     $   $   $ 9.95   $   No   $ 30     $  

Q2 2009

  27,765               9.59       No     28       (3 )

Q3 2009

  27,160               9.54       No     29       (6 )

Q4 2009

  28,980               9.69       No     28       (14 )

2010

  231,775               10.77       No     223       (58 )

2011

  138,700               10.59       No     153       (59 )

2012 – 2017

  76,820               11.29       No     57       (38 )

Put Options:

               

2009

  36,500           5.75           No     3       (21 )

2010

  36,500           5.75           No     3       (18 )

Other Collars:

               

Q1 2009

  35,550           5.24/7.95     9.90       No           73  

Q2 2009

  81,135           5.24/6.99     9.18       No           103  

Q3 2009

  85,060           5.24/6.98     9.16       No     (1 )     90  

Q4 2009

  44,860           5.39/7.28     9.49       No     (1 )     42  

2010

  25,550           6.00/7.71     11.46       No     21       29  

2011

  25,550           6.00/7.57     10.69       No     21       13  

2012 – 2020

  87,680           5.00/7.08     10.20       No     58       (53 )

CNR Swaps (b):

               

Q1 2009

  4,500       5.18               Yes           (3 )

Q2 2009

  4,550       5.18               Yes           (3 )

Q3 2009

  4,600       5.18               Yes           (4 )

Q4 2009

  4,600       5.18               Yes           (7 )

CNR Collars (b):

               

2009

  3,650           4.50     6.00       Yes           (2 )
                           

Total Natural Gas

                670       1,282  
                           

Oil (mbbls):

               

Knockout Swaps:

               

Q1 2009

  855       80.35     55.95           No           3  

Q2 2009

  865       80.43     55.95           No           1  

Q3 2009

  1,978       83.10     58.21           No            

Q4 2009

  1,978       83.05     58.21           No           (1 )

2010

  4,745       90.25     60.00           No           4  

2011

  1,095       104.75     60.00           No           7  

2012

  732       109.50     60.00           No           5  

Cap Swaps:

               

Q1 2009

  180       67.50     50.00           No           2  

Q2 2009

  182       67.50     50.00           No           1  

Other Swaps:

               

Q1 2009

  900       86.25               No           34  

Q2 2009

  910       86.25               No           29  

Counter Swaps:

               

Q1 2009

  (841 )     67.79               No           (16 )

Q2 2009

  (819 )     67.00               No           (11 )

Q3 2009

  (230 )     69.10               No           (3 )

Q4 2009

  (230 )     69.10               No           (2 )

Call Options:

               

2009

  5,110               101.79       No     3       (9 )

2010

  6,935               107.86       No     (10 )     (20 )

2011

  3,650               185.00       No     36       (2 )

2012

  3,660               185.00       No     37       (4 )

Other Collars:

               

2010

  730           90.00/80.00     136.40       No           5  
                           

Total Oil

                66       23  
                           

Total Natural Gas and Oil

              $ 736     $ 1,305  
                           

 

(a) These include options to extend an existing swap for an additional 12 months at 50,000 mmbtu/day at $8.73/mmbtu. The options are callable by the counterparty in March 2009 and March 2010 and 40,000 mmbtu/day at $11.35/mmbtu, callable by the counterparty in December 2009.
(b)

We assumed certain liabilities related to open derivative positions in connection with our acquisition of Columbia Natural Resources, LLC in November 2005. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price

 

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allocation as a liability of $592 million ($45 million liability remaining as of December 31, 2008). The recognition of the derivative liability and other assumed liabilities resulted in an increase in the total purchase price which was allocated to the assets acquired. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our natural gas and oil revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to natural gas and oil revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in natural gas and oil revenues, depending upon whether the sales price was higher or lower, respectively, than the prices assumed in the original fair value calculation. For accounting purposes, the net effect of these acquired hedges is that we hedged the production volumes at market prices on the date of our acquisition of CNR.

Pursuant to Statement of Financial Accounting Standards No. 149, Amendment of SFAS 133 on Derivative Instruments and Hedging Activities, the derivative instruments assumed in connection with the CNR acquisition are deemed to contain a significant financing element and all cash flows associated with these positions are reported as financing activity in the statement of cash flows for the periods in which settlement occurs.

We have established the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors.

Based upon the market prices at December 31, 2008, we expect to transfer approximately $345 million (net of income taxes) of the gain included in the balance in accumulated other comprehensive income to earnings during the next twelve months in the related month of production. All transactions hedged as of December 31, 2008 are expected to mature by December 31, 2022.

Additional information concerning the fair value of our natural gas and oil derivative instruments is as follows:

 

     2008     2007     2006  
     ($ in millions)  

Fair value of contracts outstanding, as of January 1

   $ (369 )   $ 345     $ (946 )

Change in fair value of contracts

     1,880       972       3,423  

Fair value of contracts when entered into

     (569 )     (295 )     (32 )

Contracts realized or otherwise settled

     9       (1,203 )     (1,254 )

Fair value of contracts when closed

     354       (188 )     (846 )
                        

Fair value of contracts outstanding, as of December 31

   $ 1,305     $ (369 )   $ 345  
                        

The change in the fair value of our derivative instruments since January 1, 2008 resulted from new contracts entered into, the settlement of derivatives for a realized gain, as well as a decrease in natural gas and oil prices. Derivative instruments reflected as current in the consolidated balance sheet represent the estimated fair value of derivative instrument settlements scheduled to occur over the subsequent twelve-month period based on market prices for natural gas and oil as of the consolidated balance sheet date. The derivative settlement amounts are not due and payable until the month in which the related underlying hedged transaction occurs.

 

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Interest Rate Risk

The table below presents principal cash flows and related weighted average interest rates by expected maturity dates. As of December 31, 2008, the fair value of the fixed-rate long-term debt has been estimated based on quoted market prices.

 

     Years of Maturity
     2009    2010    2011    2012    2013    Thereafter    Total
     ($ in millions)

Liabilities:

                    

Long-term debt – fixed-rate (a)

   $    $    $    $    $ 864    $ 9,260    $ 10,124

Average interest rate

                         7.6      5.4      5.6

Long-term debt – variable rate

   $    $    $    $ 3,474    $ 460    $    $ 3,934

Average interest rate

                    1.8      3.0           2.0

 

(a) This amount does not include the discount included in long-term debt of ($85) million and interest rate derivatives of $211 million.

Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our revolving bank credit facility. All of our other long-term indebtedness is fixed rate and, therefore, does not expose us to the risk of earnings or cash flow loss due to changes in market interest rates. However, changes in interest rates do affect the fair value of our debt.

Interest Rate Derivatives

We use interest rate derivatives to mitigate our exposure to the volatility in interest rates. For interest rate derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value are recorded on the consolidated balance sheets as assets (liabilities), and the debt’s carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Changes in the fair value of derivative instruments not qualifying as fair value hedges are recorded currently as adjustments to interest expense.

Gains or losses from interest rate derivative transactions are reflected as adjustments to interest expense in the consolidated statements of operations. Realized gains (losses) included in interest expense were $6 million, ($1) million and ($2) million in 2008, 2007 and 2006, respectively. Pursuant to SFAS 133, certain derivatives do not qualify for designation as fair value hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the consolidated statements of operations as unrealized gains (losses) within interest expense. Unrealized gains (losses) included in interest expense were ($85) million, ($40) million and $2 million in 2008, 2007 and 2006, respectively.

 

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As of December 31, 2008, the following interest rate derivatives were outstanding:

 

    Notional
Amount
($ in
millions)
  Weighted
Average
Fixed
Rate
    Weighted
Average
Floating
Rate (b)
  Fair
Value
Hedge
  Net
Premiums
($ in
millions)
  Fair
Value

($ in
millions)
 

Fixed to Floating Interest Rate:

           

Swaps

           

January 2008 – November 2020

  $ 750   6.75 %   6 mL plus 224 bp   Yes   $   $ 115  

Call Options

           

February 2009 – May 2009

  $ 750   6.75 %   6 mL plus 224 bp   No     11     (105 )

Swaption

           

January 2009

  $ 250   6.50 %   6 mL plus 200 bp   No     3      

Floating to Fixed Interest Rate:

           

Swaps

           

August 2007 – August 2010

  $ 825   4.74 %   1 – 3 mL   No         (27 )

Collars (a)

           

August 2007 – August 2010

  $ 800   4.52 %   6 mL   No         (35 )

Swaption

           

August 2009

  $ 500   2.56 %   1 mL   No     5     (10 )
                     
          $ 19   $ (62 )
                     

 

(a) The collars have ceiling and floor fixed interest rates of 5.37% and 4.52%, respectively.
(b) Month LIBOR has been abbreviated “mL” and basis points has been abbreviated “bp”.

In 2008, we closed interest rate derivatives for gains totaling $110 million of which $30 million was recognized in interest expense. The remaining $80 million was from interest rate derivatives designated as fair value hedges and the settlement amounts received will be amortized as a reduction to interest expense over the remaining term of the related senior notes ranging from five to twelve years.

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 a cross currency swap to mitigate our exposure to fluctuations in the euro relative to the dollar over the term of the notes. Under the terms of the cross currency swap, on each semi-annual interest payment date, the counterparties will pay Chesapeake €19 million and Chesapeake will pay the counterparties $30 million, which will yield an annual dollar-equivalent interest rate of 7.491%. Upon maturity of the notes, the counterparties will pay Chesapeake €600 million and Chesapeake will pay the counterparties $800 million. The terms of the cross currency swap were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. Through the cross currency swap, we have eliminated any potential variability in Chesapeake’s expected cash flows related to changes in foreign exchange rates and therefore the